filings.toolsItem 7. MANAGEMENT’S DISCUSSION AND
140K characters. Original on sec.gov · Markdown
Item 7. MANAGEMENT’S DISCUSSION AND
MANAGEMENT’S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
Management’s
Discussion and Analysis is the company’s analysis of its financial performance and of
significant trends that may affect future performance.
It should be read in conjunction with the financial
statements and notes, and supplemental oil
and gas disclosures included elsewhere in this report.
It contains
forward-looking statements including, without limitation, statements
relating to the company’s
plans,
strategies, objectives, expectations and intentions
that are made pursuant to the “safe harbor” provisions of
the Private Securities Litigation Reform Act of
The words “anticipate,” “believe,” “budget,”
“continue,” “could,” “effort,” “estimate,” “expect,”
“forecast,” “goal,” “guidance,” “intend,” “may,”
“objective,” “outlook,” “plan,” “potential,” “predict,” “projection,” “seek,”
“should,” “target,” “will,”
“would,” and similar expressions identify forward-looking statements.
The company does not undertake to
update, revise or correct any of the forward-looking information unless required to do so under the federal
securities laws.
Readers are cautioned that such forward-looking statements should be read in conjunction
with the company’s disclosures under the heading: “CAUTIONARY STATEMENT
FOR THE PURPOSES OF
THE ‘SAFE HARBOR’ PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF
1995,” beginning on page
The terms “earnings” and “loss” as used in Management’s Discussion and Analysis refer to net income (loss)
attributable to ConocoPhillips.
BUSINESS ENVIRONMENT AND EXECUTIVE
OVERVIEW
ConocoPhillips is an independent E&P company
with operations and activities in 15 countries.
Our diverse,
low cost of supply portfolio includes resource-rich
unconventional plays in North America;
conventional
assets in North America, Europe and Asia;
LNG developments; oil sands assets in Canada;
and an inventory of
global conventional and unconventional exploration
prospects.
Headquartered in Houston, Texas, at
December 31, 2020, we employed approximately
9,700 people worldwide and had total
assets of $63 billion.
Completed Acquisition of Concho Resources Inc.
On January 15, 2021, we completed our acquisition
of Concho Resources Inc. (Concho), an independent
oil
and gas exploration and production company
with operations across New Mexico and West Texas.
The
addition of complementary acreage in the
Delaware and Midland Basins creates a sizeable
Permian presence to
augment our leading unconventional positions
in the Eagle Ford and Bakken in the Lower 48
and the Montney
in Canada.
Consideration for the all-stock transaction was
valued at $13.1 billion, in which 1.46 shares
of ConocoPhillips
common stock was exchanged for each outstanding
share of Concho common stock, resulting
in the issuance
of approximately 286 million shares of ConocoPhillips
common stock.
We also assumed $3.9 billion in
aggregate principal amount of outstanding debt for
Concho, which was recorded at fair value of $4.7
billion as
of the closing date.
The combined companies are expected to
capture approximately $750 million of annual
cost and capital savings by 2022.
For additional information
related to this transaction, see Note 25—
Acquisition of Concho Resources Inc. in the
Notes to Consolidated Financial Statements.
Overview
The energy landscape changed dramatically in 2020 with
simultaneous demand and supply shocks that drove
the industry into a severe downturn.
The demand shock was triggered by the
COVID-19 pandemic,
which
continues to have unprecedented social and economic
consequences.
Mitigation efforts to stop the spread of
this highly-contagious disease include stay-at-home
orders and business closures that caused
sharp
contractions in economic activity worldwide.
The supply shock was triggered by disagreements
between
OPEC and Russia, beginning in early March 2020,
which resulted in significant supply coming
onto the
market
and an oil price war.
These dual demand and supply shocks caused
oil prices to collapse as we exited
the first quarter of 2020.
As we entered the second quarter of 2020, predictions
of COVID-19 driven global oil demand losses
intensified, with forecasts
of unprecedented demand declines.
Based on these forecasts, OPEC plus nations
held an emergency meeting, and in April they announced
a coordinated production cut that was unprecedented
in both its magnitude and duration.
The OPEC plus agreement spans from May 2020
until April 2022, with
the volume of production cuts easing over time.
Additionally, non-OPEC plus countries, including the U.S.,
Canada, Brazil and other G-20 countries,
announced organic reductions to production through the
release of
drilling rigs, frac crews, normal field decline
and curtailments.
Despite these planned production decreases,
the supply cuts were not timely enough to overcome
significant demand decline.
Futures prices for April WTI
closed under $20 a barrel for the first time
since 2001, followed by May WTI settling below zero on the
day
before futures contracts expiry, as holders of May futures contracts struggled to exit
positions and avoid taking
physical delivery.
As storage constraints approached, spot prices in
April for certain North American
landlocked grades of crude oil were in the single digits
or even negative for particularly remote or low-grade
crudes, while waterborne priced crudes such as
Brent sold at a relative advantage.
The extreme volatility
experienced
in the first half of the year settled down in the
second half of the year, with WTI crude oil prices
exiting the year near $50 per barrel.
Since the start of the severe downturn, we have closely
monitored the market and taken prudent actions in
response to this situation.
We entered 2020 in a position of relative strength, with cash and cash equivalents of
more than $5 billion, short-term investments
of $3 billion, and an undrawn credit facility
of $6 billion, totaling
approximately $14 billion in available liquidity.
Additionally, we had several entity and asset sales
agreements in place, which generated $1.3 billion
in proceeds from dispositions during 2020.
For more
information about the sales of our Australia-West and non-core Lower 48 assets, see
Note 4—Asset
Acquisitions and Dispositions in the Notes to
Consolidated Financial Statements.
This relative advantage
allowed us to be measured in our response to
the sudden change in business environment.
In March, we announced an initial set of actions
to address the downturn and followed up with additional
actions in April.
The combined announcements reflected a reduction
in our 2020 operating plan capital of $2.3
billion, a reduction to our operating costs of
$600 million and suspension of our share
repurchase program.
These actions decreased uses of cash by approximately
$5 billion in 2020.
We also established a framework
for evaluating our assets and implementing
economic production curtailments considering
the weakness in oil
prices during the second quarter of 2020, which resulted
in taking an additional significant step of voluntarily
curtailing production, predominantly from
operated North American assets.
Due to our strong balance sheet,
we were in an advantaged position to forgo some production
and cash flow in anticipation of receiving higher
cash flows for those volumes in the future.
In the second quarter, we curtailed production by an estimated 225 MBOED,
with 145 MBOED of the
curtailments from the Lower 48, 40 MBOED from
Alaska and 30 MBOED from our Surmont operation
in
Canada.
The remainder of the second-quarter curtailments
were primarily in Malaysia.
Other industry
operators also cut production and development
plans and as we progressed through the second quarter, certain
stay-at-home restrictions eased, which partially
restored lost demand, and WTI and Brent prices
exited the
second quarter around $40 per barrel.
Based on our economic framework, we began
restoring production from
voluntary curtailments in July, and with oil stabilizing around $40 per barrel, we
ended our curtailment
program during the third quarter.
Curtailments in the third quarter averaged approximately
90 MBOED, with
65 MBOED attributable to the Lower 48 and 15 MBOED
to Surmont.
In August 2020, we acquired
additional Montney acreage for cash consideration
of $382 million, after
customary post-closing adjustments.
We also assumed $31 million in financing obligations for associated
partially owned infrastructure.
This acquisition consisted primarily
of undeveloped properties and included
140,000 net acres in the liquids-rich Inga Fireweed
asset Montney zone, which is directly adjacent
to our
existing Montney position.
The transaction increased our Montney acreage
position to approximately 295,000
net acres with a 100 percent working interest.
See Note 4—Acquisitions and Dispositions in
the Notes to
Consolidated Financial Statements for additional
information.
In October 2020, we announced an increase to our
quarterly dividend from $0.42 per share to $0.43
per share
and resumed
share repurchases before suspending our
share repurchase program upon entry into
our definitive
agreement to acquire Concho.
We resumed shares repurchases in February 2021 after completion of our
Concho acquisition.
We ended the year with over $12 billion of liquidity, comprised of $3.0 billion in cash
and cash equivalents, $3.6 billion in short-term
investments, and available borrowings under our credit
facility
of $5.7 billion.
Our expectation is that commodity prices will
remain cyclical and volatile, and a successful
business strategy
in the E&P industry must be resilient in
lower price environments, at the same time retaining
upside during
periods of higher prices.
While we are not impervious to current market
conditions, we believe our decisive
actions over the last several years of focusing on free
cash flow generation, high-grading our asset
base,
lowering the cost of supply of our investment
resource portfolio, and strengthening our
balance sheet have put
us in a strong relative position compared to our
independent E&P peers.
We remain committed to the core
principles of our value proposition, namely, free cash flow generation,
a strong balance sheet, commitment to
differential returns of and on capital,
and ESG leadership.
Our workforce and operations have adjusted to
mitigate the impacts of the COVID-19
pandemic.
We have
operations in remote areas with confined spaces,
such as offshore platforms, the North Slope of Alaska,
Curtis
Island in Australia, western Canada and Indonesia,
where viruses could rapidly spread.
Personnel are asked to
perform a self-assessment for symptoms of illness
each day and, when appropriate, are subject to
more
restrictive measures before traveling to and working
on location.
Staffing levels in certain operating locations
have been reduced to minimize health risk exposure
and increase social distancing.
A portion of our office
staff have continued to work successfully remotely, with offices around the world carefully
designing and
executing a flexible, phased reentry, following national, state and local guidelines.
These mitigation measures
have thus far been effective at reducing business operation
disruptions.
Workforce health and safety remains
the overriding driver for our actions and we have
demonstrated our ability to adapt to local
conditions as
warranted.
The marketing and supply chain
side of our business has also adapted in response
to COVID-19.
Our
commercial organization managed transportation commitments
during our voluntary curtailment program.
Our supply chain function is proactively working
with vendors to ensure the continuity of our business
operations, monitor distressed service and materials
providers, capture deflation opportunities, and pursue
cost
reduction efforts.
We also enhanced our focus on counterparty risk monitoring during this period
and
requested credit assurances when applicable.
Operationally, we remain focused on safely executing the business.
In 2020, production of 1,127 MBOED
generated cash provided by operating activities
of $4.8 billion.
We invested $4.7
billion into the business in
the form of capital expenditures, including $0.5
billion of acquisition capital, and paid dividends
to
shareholders of $1.8 billion.
Production decreased 221 MBOED or 16 percent
in 2020, compared to 2019.
Production excluding
Libya for 2020 was 1,118 MBOED.
Adjusting for estimated curtailments
of
approximately 80 MBOED; closed acquisitions
and dispositions;
and excluding Libya, production for 2020
would have been 1,176 MBOED, a decrease of 15
MBOED compared with 2019 production.
This decrease
was primarily due to normal field decline, partly
offset by new wells online in the Lower 48, Canada,
Norway,
Alaska and China.
Production from Libya averaged 9 MBOED
as it was in force majeure during a significant
portion of the year.
Key Operating and Financial Summary
Significant items during 2020 and recent announcements
included the following:
●
Enhanced both our portfolio and financial framework through the
acquisition of Concho in an all-stock
transaction, as well as purchasing bolt-on acreage in Canada and Lower
●
Full-year production, excluding Libya, of 1,118
MBOED; curtailed approximately 80 MBOED during the
year.
●
Cash provided by operating activities was $4.8 billion.
●
Generated $1.3 billion in disposition proceeds from non-core asset sales.
●
Distributed $1.8 billion in dividends and repurchased $0.9 billion of shares.
●
Ended the year with cash and cash equivalents totaling $3.0 billion and
short-term investments of $3.6
billion,
equaling $6.6 billion in ending cash and cash equivalents and short-term investments.
●
Announced two significant discoveries in Norway and achieved first production
at Tor II; continued
appraisal drilling and started up first pads and related infrastructure
in Montney.
●
Adopted a Paris-aligned climate risk framework with ambition to achieve net
-zero operated emissions by
2050 as part of our commitment to ESG excellence.
●
Recognized impairments of proved and unproved properties totaling $1.3
billion after-tax.
Business Environment
Brent crude oil prices averaged $42 per barrel in 2020,
compared with $64 per barrel in 2019.
The energy
industry has periodically experienced this type
of volatility due to fluctuating supply-and-demand
conditions
and such volatility may persist for the foreseeable
future.
Commodity prices are the most significant
factor
impacting our profitability and related reinvestment
of operating cash flows into our business.
Our strategy is
to create value through price cycles by delivering
on the foundational principles that underpin our
value
proposition; free cash flow generation,
a strong balance sheet,
commitment to differential returns of and on
capital,
and ESG leadership.
Operational and Financial Factors Affecting
Profitability
The focus areas we believe will drive our success
through the price cycles include:
●
Free cash flow generation.
This is a core principle of our value proposition.
Our goal is to achieve
strong free cash flow by exercising capital discipline,
controlling our costs, and safely and reliably
delivering production.
Throughout the price cycles, we expect to make capital
investments sufficient
to sustain production.
Free cash flow provides funds that are available
to return to shareholders,
strengthen the balance sheet to deliver on our
priorities through the price cycles, or reinvest back into
the business for future cash flow expansion.
o
Maintain capital allocation discipline.
We participate in a commodity price-driven and
capital-intensive industry, with varying lead times from when an investment
decision is made
to the time an asset is operational and generates cash
flow.
As a result, we must invest
significant capital dollars to explore for new oil
and gas fields, develop newly discovered
fields, maintain existing fields, and construct pipelines
and LNG facilities.
We allocate
capital across a geographically diverse, low cost
of supply resource base, which combined
with legacy assets results in low production decline.
Cost of supply is the WTI equivalent
price that generates a 10 percent after-tax return
on a point-forward and fully burdened basis.
Fully burdened includes capital infrastructure,
foreign exchange, price related inflation and
G&A.
In setting our capital plans, we exercise a rigorous
approach that evaluates projects
using this cost of supply criteria, which we believe
will lead to value maximization and cash
flow expansion using an optimized investment
pace, not production growth for growth’s sake.
Our cash allocation priorities call for the investment
of sufficient capital to sustain production
and pay the existing dividend.
Additional capital may be allocated toward
growth, but
discipline will be maintained.
In February 2021, we announced 2021 operating
plan capital for the combined company of
$5.5 billion.
The plan includes $5.1 billion to sustain current
production and $0.4 billion for
investment in major projects, primarily in
Alaska, in addition to ongoing exploration
appraisal activity.
The operating plan capital budget of $5.5 billion
is expected to deliver production from the
combined company of approximately 1.5 MMBOED
in 2021.
This production guidance
excludes Libya.
o
Control costs and expenses.
Controlling operating and overhead costs,
without compromising
safety and environmental stewardship, is a high priority.
We monitor these costs using
various methodologies that are reported to senior management
monthly, on both an absolute-
dollar basis and a per-unit basis.
Managing operating and overhead costs is
critical to
maintaining a competitive position in our industry, particularly in a low commodity
price
environment.
The ability to control our operating and overhead
costs impacts our ability to
deliver strong cash from operations.
In 2020, our production and operating expenses
were 18
percent lower than 2019, primarily due to decreased
wellwork and transportation costs
resulting from production curtailments across
our North American operated assets as well as
the absence of costs related to our U.K. and
Australia-West divestitures.
For more
information related to our U.K. and Australia-West divestitures, see note 4—Acquisitions
and
Dispositions in the Notes to Consolidated Financial
Statements.
At the time of the Concho acquisition announcement
in October 2020, we announced planned
cost reductions and quantified $350 million
of annual expense savings expected to be
achieved by 2022.
These reductions included approximately $150 million
due to streamlining
our internal organization to appropriate levels given the
current industry environment and
recent asset sales; $100 million of G&A and
G&G due to a refocused exploration program;
and $100 million of redundant G&A costs on
a combined basis related to the Concho
acquisition.
Subsequent to the transaction announcement,
we identified $250 million of
further cost reductions from the combined companies
to be achieved by 2022.
o
Optimize our portfolio.
In January 2021, we completed the acquisition
of Concho and
significantly increased our unconventional portfolio
with years of low cost of supply
investments.
The addition of complementary acreage in the
Delaware and Midland basins
creates a sizeable Permian presence to augment our leading
unconventional positions in the
Eagle Ford and Bakken in the Lower 48.
We added to our unconventional Montney position
with an asset acquisition that consisted primarily
of undeveloped properties directly adjacent
to our existing acreage.
These acquisitions followed several non-core asset
sales earlier in the year including
Australia-West in our Asia Pacific segment,
and Niobrara and Waddell Ranch in the Lower
We managed the portfolio well during a turbulent year, with asset sales entered at the end
of 2019 generating $1.3 billion of proceeds from dispositions
in the first half of 2020,
followed by opportunistic acquisitions of unconventional
assets in the second half of 2020
after commodity prices had dropped.
We will continue to evaluate our assets to determine
whether they compete for capital within our portfolio
and will optimize the portfolio as
necessary, directing capital towards the most competitive investments.
●
A strong balance sheet.
We believe balance sheet strength is critical in a cyclical business such as
ours.
Our strong operating performance buffered by a solid
balance sheet enables us to deliver on our
priorities through the price cycles.
Our priorities include execution of our
development plans,
maintaining a growing dividend, and returning competitive
returns of capital to shareholders.
●
Commitment to differential returns of and on capital.
We believe in delivering value to our
shareholders via a growing, sustainable dividend
supplemented by additional returns of
capital,
including share repurchases.
In 2020, we paid dividends on our common stock
of approximately $1.8
billion and repurchased $0.9
billion of our common stock.
Combined, our dividend and repurchases
represented
57 percent of our net cash provided by operating
activities.
Since we initiated our current
share repurchase program in late 2016, we have repurchased
189 million shares for $10.5 billion,
which represents approximately 15 percent of shares
outstanding as of September 30, 2016.
As of
December 31, 2020, $14.5 billion of repurchase
authority remained of the $25 billion share repurchase
program our Board of Directors had authorized.
Repurchases are made at management’s discretion,
at prevailing prices, subject to market conditions
and other factors.
See “Item 1A—Risk Factors Our
ability to declare and pay dividends and repurchase
shares is subject to certain considerations.”
In October 2020, we announced that our Board
of Directors approved an increase to our quarterly
dividend of $0.42 per share to $0.43 per share.
In February 2021, we resumed share repurchases
after
the completion of our Concho acquisition.
●
ESG Leadership.
Safety and environmental stewardship,
including the operating integrity of our
assets, remain our highest priorities, and we
are committed to protecting the health and
safety of
everyone who has a role in our operations and
the communities in which we operate.
We strive to
conduct our business with respect and care for
both the local and global environment and
systematically manage risk to drive sustainable business
growth.
Demonstrating our commitment to
sustainability and environmental stewardship, in
October 2020, we announced our adoption of a Paris-
aligned climate risk framework as part of our continued
leadership in ESG excellence.
This
comprehensive climate risk strategy should enable
us to sustainably meet global energy demand while
delivering competitive returns through the energy transition.
We have set a target to reduce our gross
operated (scope 1 and 2) emissions intensity
by 35 to 45 percent from 2016 levels by 2030,
with an
ambition to achieve net zero by 2050 for operated
emissions.
We are advocating for reduction of
scope 3 end-use emissions intensity through our
support for a U.S. carbon price and reaffirmed
our
commitment to the Climate Leadership Council.
We have joined the World
Bank Flaring Initiative to
work towards zero routine flaring of gas by 2030
and are the first U.S.-based oil and gas company
to
adopt a Paris-aligned climate risk strategy.
●
Add to our proved reserve base.
We primarily add to our proved reserve base in three ways:
o
Purchases of increased interests in existing
fields and acquisitions.
o
Application of new technologies and processes
to improve recovery from existing fields.
o
Successful exploration, exploitation and development
of new and existing fields.
As required by current authoritative guidelines,
the estimated future date when an asset will reach
the
end of its economic life is based on historical 12-month
first-of-month average prices and current
costs.
This date estimates when production will
end and affects the amount of estimated reserves.
Therefore, as prices and cost levels change from
year to year, the estimate of proved reserves also
changes.
Generally, our proved reserves decrease as prices decline and increase as prices
rise.
Reserve replacement represents the net change in
proved reserves, net of production, divided
by our
current year production, as shown in our supplemental
reserve table disclosures.
Our reserve
replacement was negative 86 percent in 2020, reflecting
the impact of lower prices, which reduced
reserves by approximately 600 MMBOE.
Our organic reserve replacement, which excluded a net
decrease of 7 MMBOE from sales and purchases,
was negative 84 percent in 2020.
In the three years ended December 31, 2020, our reserve
replacement was 59 percent, primarily
impacted by lower prices in 2020.
Our organic reserve replacement during the three years
ended
December 31, 2020, which excluded
a net increase of 89 MMBOE related to sales
and purchases, was
53 percent.
Access to additional resources may become increasingly
difficult as commodity prices can make
projects uneconomic or unattractive.
In addition, prohibition of direct investment
in some nations,
national fiscal terms, political instability, competition from national oil companies,
and lack of access
to high-potential areas due to environmental or other
regulation may negatively impact our
ability to
increase our reserve base.
As such, the timing and level at which we add
to our reserve base may, or
may not, allow us to replace our production
over subsequent years.
●
Apply technical capability.
We leverage our knowledge and technology to create value and safely
deliver on our plans.
Technical strength is part of our heritage and allows us to economically
convert
additional resources to reserves, achieve greater
operating efficiencies and reduce our environmental
impact.
Companywide, we continue to leverage knowledge
of technological successes across our
operations.
We have embraced the digital transformation and are using digital innovations to
work and operate
more efficiently.
Predictive analytics have been adopted in our operations
and planning process.
Artificial intelligence, machine learning and
deep learning are being used for emissions
monitoring,
seismic advancements and advanced controls in
our field operations.
●
Attract, develop and retain a talented work force.
We strive to attract, develop and retain individuals
with the knowledge and skills to successfully
execute our business strategy in a manner
exemplifying
our core values and ethics.
We offer university internships across multiple disciplines to attract the
best early career talent.
We also recruit experienced hires to fill critical skills and maintain a broad
range of expertise and experience.
We promote continued learning, development and technical
training through structured development programs
designed to enhance the technical and functional
skills of our employees.
Other Factors Affecting
Profitability
Other significant factors that can affect our profitability
include:
●
Energy commodity prices.
Our earnings and operating cash flows generally
correlate with industry
price levels for crude oil and natural gas.
Industry price levels are subject to factors external
to the
company and over which we have no control, including
but not limited to global economic health,
supply disruptions or fears thereof caused by civil
unrest or military conflicts, actions taken by
OPEC
and other producing countries, environmental laws,
tax regulations, governmental policies and
weather-related disruptions.
The following graph depicts the average benchmark
prices for WTI
crude oil, Brent crude oil and U.S. Henry Hub natural
gas:
Brent crude oil prices averaged $41.68 per barrel
in 2020, a decrease of 35 percent compared
with
$64.30 per barrel in 2019.
Similarly, WTI crude oil prices decreased 31 percent from $57.02 per
barrel in 2019 to $39.37 per barrel in 2020.
Crude oil prices were lower due to the dual
demand and
supply shocks.
The demand shock was triggered by the
COVID-19 pandemic, which continues to
have unprecedented social and economic consequences.
The supply shock was triggered by
disagreements between OPEC and Russia, beginning
in early March 2020, which resulted in
significant supply coming onto the market
and created higher inventory levels.
Henry Hub natural gas prices
decreased 21 percent from an average of $2.63
per MMBTU in 2019 to
$2.08 per MMBTU in 2020.
Henry Hub prices were depressed due to high
storage levels and weak
demand.
Our realized bitumen price decreased 75 percent
from an average of $31.72 per barrel
in 2019 to $8.02
per barrel in 2020.
The decrease was largely driven by weakness in WTI,
reflective of impacts from
the COVID-19 pandemic.
The WCS differential to WTI at Hardisty remained fairly
flat as
curtailment orders imposed by the Alberta Government,
which limited production from the province,
continued throughout 2020.
We continue to optimize bitumen price realizations through
improvements in alternate blend capability which
results in lower diluent costs and access
to the U.S.
Gulf Coast market through rail and pipeline contracts.
Our worldwide annual average realized price decreased
34 percent from $48.78
per BOE in 2019 to
$32.15
per BOE in 2020 primarily due to lower realized
oil, natural gas and bitumen prices.
North America’s energy supply landscape has been transformed from one of resource
scarcity to one
of abundance.
In recent years, the use of hydraulic fracturing
and horizontal drilling in
unconventional formations has led to increased industry
actual and forecasted crude oil and natural
gas production in the U.S.
Although providing significant short-
and long-term growth opportunities
for our company, the increased abundance of crude oil and natural gas due to development
of
unconventional plays could also have adverse financial
implications to us, including: an extended
period of low commodity prices; production curtailments;
and delay of plans to develop areas such as
unconventional fields.
Should one or more of these events occur, our revenues would
be reduced, and
additional asset impairments might be possible.
●
Impairments.
We participate in a capital-intensive industry.
At times, our PP&E and investments
become impaired when, for example, commodity
prices decline significantly for long
periods of time,
our reserve estimates are revised downward, or a
decision to dispose of an asset leads to
a write-down
to its fair value.
We may also invest large amounts of money in exploration which, if exploratory
drilling proves unsuccessful, could lead to a material
impairment of leasehold values.
As we optimize
our assets in the future, it is reasonably possible
we may incur future losses upon sale or
impairment
charges to long-lived assets used in operations, investments
in nonconsolidated entities accounted for
under the equity method, and unproved properties.
For additional information on our impairments,
see Note 7—Suspended Wells and Exploration Expenses and Note 8—Impairments, in
the Notes to
Consolidated Financial Statements.
●
Effective tax rate.
Our operations are in countries with different tax rates
and fiscal structures.
Accordingly, even in a stable commodity price and fiscal/regulatory environment,
our overall
effective tax rate can vary significantly between periods
based on the “mix” of before-tax earnings
within our global operations.
●
Fiscal and regulatory environment.
Our operations can be affected by changing economic,
regulatory
and political environments in the various countries
in which we operate, including the U.S.
Civil
unrest or strained relationships with governments
may impact our operations or investments.
These
changing environments could negatively impact our
results of operations, and further changes to
increase government fiscal take could have a
negative impact on future operations.
Our management
carefully considers the fiscal and regulatory
environment when evaluating projects or
determining the
levels and locations of our activity.
Outlook
Production and Capital
In February 2021, we announced 2021 operating
plan capital for the combined company of $5.5
billion.
The
plan includes $5.1 billion to sustain current
production and $0.4 billion for investment
in major projects,
primarily in Alaska, in addition to ongoing
exploration appraisal activity.
The operating plan capital budget of $5.5 billion
is expected to deliver production from the combined
company
of approximately 1.5 MMBOED in 2021.
This production guidance excludes Libya.
Restructuring
As a result of the acquisition of Concho, we commenced
a restructuring program in the first quarter
of 2021 in
association with combining the operations of the
two companies.
We expect to incur significant non-recurring
transaction and acquisition-related costs in
2021 for employee severance payments; incremental
pension
benefit costs related to the workforce reductions; employee
retention costs; employee relocations; fees
paid to
financial, legal, and accounting advisors; and
filing fees.
We currently cannot estimate these costs, as well as
other unanticipated items,
and expect to recognize the majority
of these expenses in the first quarter of 2021.
Operating Segments
We manage our operations through six operating segments, which are primarily
defined by geographic region:
Alaska; Lower 48; Canada; Europe, Middle East
and North Africa; Asia Pacific; and Other International.
Corporate and Other represents income and costs
not directly associated with an operating
segment, such as
most interest expense, premiums incurred on the
early retirement of debt, corporate overhead,
certain
technology activities, as well as licensing revenues.
Our key performance indicators, shown in the statistical
tables provided at the beginning of the operating
segment sections that follow, reflect results from our operations, including commodity
prices and production.
RESULTS OF OPERATIONS
Effective with the third quarter of 2020, we have restructured our segments to align with
changes to our
internal organization.
The Middle East business was realigned from the Asia Pacific and Middle East
segment
to the Europe and North Africa segment.
The segments have been renamed the Asia Pacific
segment and the
Europe, Middle East and North Africa segment.
We have revised segment information disclosures and
segment performance metrics presented within our results of operations for the
current and prior years.
This section of the Form 10-K
discusses year-to-year comparisons between 2020
and 2019.
For discussion of
year-to-year comparisons between 2019 and 2018, see
"Management's Discussion and Analysis
of Financial
Condition and Results of Operations" in Exhibit
99.1
—
, Item 7 filed with our Form 8-K filed
on November 16,
Consolidated Results
A summary of the company’s net income (loss) attributable to ConocoPhillips
by business segment follows:
Millions of Dollars
Years Ended December 31
2020
2019
2018
Alaska
$
(719)
1,520
1,814
Lower 48
(1,122)
1,747
Canada
(326)
Europe, Middle East and North Africa
3,170
2,594
Asia Pacific
1,483
1,342
Other International
(64)
Corporate and Other
(1,880)
(1,667)
Net income (loss) attributable to ConocoPhillips
$
(2,701)
7,189
6,257
2020 vs. 2019
Net income (loss) attributable to ConocoPhillips
decreased $9.9 billion in 2020.
The decrease was mainly due
to:
●
Lower realized commodity prices.
●
Lower sales volumes due to normal field decline,
asset dispositions and production curtailments.
For
additional information related to dispositions,
see Note 4—Asset Acquisitions and Dispositions
in the
Notes to Consolidated Financial Statements.
●
The absence of a $2.1 billion after-tax gain associated
with the completion of the sale of two
ConocoPhillips U.K. subsidiaries.
For additional information, see Note 4—Asset
Acquisitions and
Dispositions in the Notes to Consolidated Financial
Statements.
●
An unrealized loss of $855 million after-tax
on our Cenovus Energy (CVE) common shares in 2020,
as compared to a $649 million after-tax unrealized
gain on those shares in 2019.
●
A $648 million after-tax impairment for the associated
carrying value of capitalized undeveloped
leasehold costs and an equity method investment
related to our Alaska North Slope Gas
asset.
For
additional information, see Note 7—Suspended
Wells and Exploration Expenses, in the Notes to
Consolidated Financial Statements.
●
Increased impairments
primarily related to developed properties
in our non-core assets which were
written down to fair value due to lower commodity
prices and development plan changes.
For
additional information, see Note 8—Impairments
and Note 14—Fair Value Measurement in the Notes
to Consolidated Financial Statements.
●
The absence of other income of $317 million after-tax
related to our settlement agreement with
PDVSA.
These decreases in net income (loss) were partly
offset by:
●
Lower production and operating expenses, primarily
due to the absence of costs related to our U.K.
and Australia-West divestitures and decreased wellwork and transportation costs
resulting from
production curtailments across our North American
operated assets.
●
A $597 million after-tax gain on dispositions related
to our Australia-West divestiture.
●
Lower DD&A expenses, primarily due to lower
volumes related to normal field decline and
production curtailments as well as impacts
of our Australia-West and U.K. divestitures.
Partly
offsetting this decrease, was higher DD&A expenses
due to price-related downward reserve revisions.
Income Statement Analysis
2020 vs. 2019
Sales and other operating revenues decreased 42 percent
in 2020, mainly due to lower realized commodity
prices and lower sales volumes.
Sales volumes decreased due to normal field
decline, production curtailments
from our North American operated assets and the
divestiture of our U.K. assets in the third
quarter of 2019 and
our Australia-West assets in the second quarter of 2020.
Equity in earnings of affiliates decreased $347 million
in 2020, primarily due to lower earnings from
QG3 and
APLNG because of lower LNG prices.
Partly offsetting this decrease was the absence
of impairments related
to equity method investments in our Lower 48 segment
of $155 million and the absence of a $118 million
deferred tax adjustment at QG3, reported in our
Europe, Middle East and North Africa segment.
Gain on dispositions decreased $1.4 billion in
2020, primarily due to the absence of a $1.7 billion
before-tax
gain associated with the completion of the sale
of two ConocoPhillips U.K. subsidiaries.
Partly offsetting the
decrease was a $587 million before-tax gain associated
with our Australia-West divestiture.
For more
information related to these dispositions, see Note
4—Asset Acquisitions and Dispositions
in the Notes to
Consolidated Financial Statements.
Other income (loss) decreased $1.9 billion
in 2020, primarily due to a before-tax unrealized
loss of $855
million on our CVE common shares in 2020, and
the absence of a $649 million before-tax unrealized
gain on
those shares in 2019.
Additionally, other income (loss) decreased due to the absence of $325 million
before-
tax related to our settlement agreement with PDVSA.
For discussion of our CVE shares, see Note 6—Investment
in Cenovus Energy in the Notes to Consolidated
Financial Statements.
For discussion of our PDVSA settlement,
see Note 12—Contingencies and
Commitments in the Notes to Consolidated Financial
Statements.
Purchased commodities decreased 32 percent in
2020, primarily due to lower natural gas
and crude oil prices;
lower crude oil and natural gas volumes purchased;
and the divestiture of our U.K. assets in the
third quarter of
2019 and our Australia-West assets in the second quarter of 2020.
Production and operating expenses decreased $978
million in 2020, primarily due to reduced activities
and
transportation costs associated with lower activity
across our North American operated assets in
response to
the low commodity price environment and the
absence of costs related to our U.K. and Australia-West
divestitures.
Selling, general and administrative expenses decreased
$126 million in 2020, primarily due to lower
costs
associated with compensation and benefits,
including mark to market impacts of certain
key employee
compensation programs.
Exploration expenses increased $714 million
in 2020, primarily due to an $828 million before-tax
impairment
for the entire carrying value of capitalized undeveloped
leasehold costs related to our Alaska
North Slope Gas
asset.
Partly offsetting this increase, was the absence of
a $141 million before-tax leasehold impairment
expense due to our decision to discontinue exploration
activities in the Central Louisiana Austin
Chalk trend.
For additional information, see Note 7—Suspended
Wells and Exploration Expenses, in the Notes to
Consolidated Financial Statements.
Impairments increased $408 million in
2020, primarily related to developed properties
in our non-core assets
which were written down to fair value due to lower
commodity prices and development plan changes.
For
additional information, see Note 8—Impairments
and Note 14—Fair Value Measurement in the Notes to
Consolidated Financial Statements.
Taxes other than income taxes decreased $199 million in 2020, primarily due
to lower commodity prices and
volumes.
Foreign currency transaction (gains) losses decreased
$138 million in 2020, due to gains recognized
from
foreign currency derivatives and other foreign
currency remeasurements.
For additional information, see Note
13—Derivative and Financial Instruments
in the Notes to Consolidated Financial Statements.
See Note 18—Income Taxes, in the Notes to Consolidated Financial Statements,
for information regarding our
income tax provision (benefit) and effective tax rate.
Summary Operating Statistics
2020
2019
2018
Average Net Production
Crude oil (MBD)
Consolidated Operations
Equity affiliates
Total crude oil
Natural gas liquids (MBD)
Consolidated Operations
Equity affiliates
Total natural gas liquids
Bitumen (MBD)
Natural gas (MMCFD)
Consolidated Operations
1,339
1,753
1,743
Equity affiliates
1,055
1,052
1,031
Total natural gas
2,394
2,805
2,774
Total Production
(MBOED)
1,127
1,348
1,283
Dollars Per Unit
Average Sales Prices
Crude oil (per bbl)
Consolidated Operations
$
39.56
60.98
68.03
Equity affiliates
39.02
61.32
72.49
Total crude oil
39.54
60.99
68.13
Natural gas liquids (per bbl)
Consolidated Operations
12.90
18.73
29.03
Equity affiliates
32.69
36.70
45.69
Total natural gas liquids
14.61
20.09
30.48
Bitumen (per bbl)
8.02
31.72
22.29
Natural gas (per mcf)
Consolidated Operations
3.17
4.25
5.40
Equity affiliates
3.71
6.29
6.06
Total natural gas
3.41
5.03
5.65
Millions of Dollars
Worldwide Exploration Expenses
General and administrative; geological and geophysical,
lease rental, and other
$
Leasehold impairment
Dry holes
$
1,457
We explore for, produce, transport and market crude oil, bitumen, natural gas, LNG and NGLs on
a worldwide
basis.
At December 31, 2020, our operations were
producing in the U.S., Norway, Canada, Australia,
Indonesia, China, Malaysia, Qatar and Libya.
2020 vs. 2019
Total production, including Libya, of 1,127 MBOED decreased 221 MBOED or 16
percent in 2020 compared
with 2019,
primarily due to:
●
Normal field decline.
●
The divestiture of our U.K. assets in the third
quarter of 2019 and our Australia-West assets in the
second quarter of 2020.
●
Production curtailments of approximately 80 MBOED,
primarily from North American operated
assets and Malaysia, in response to the low crude
oil price environment.
●
Less production in Libya due to the forced shutdown
of the Es Sider export terminal and other
eastern
export terminals after a period of civil unrest.
The decrease in production during 2020 was partly
offset by:
●
New wells online in the Lower 48, Canada,
Norway, Alaska and China.
Production excluding Libya for 2020 was 1,118 MBOED.
Adjusting for estimated curtailments
of
approximately 80 MBOED and closed acquisitions
and dispositions, production for 2020 would
have been
1,176 MBOED, a decrease of 15 MBOED compared
with 2019.
This decrease was primarily due to normal
field decline, partly offset by new wells online in the
Lower 48, Canada, Norway, Alaska and China.
Production from Libya averaged 9 MBOED as it
was in force majeure during a significant portion
of the year.
Alaska
2020
2019
2018
Net Income (Loss) Attributable to ConocoPhillips
(millions of dollars)
$
(719)
1,520
1,814
Average Net Production
Crude oil (MBD)
Natural gas liquids (MBD)
Natural gas (MMCFD)
Total Production
(MBOED)
Average Sales Prices
Crude oil ($ per bbl)
$
42.12
64.12
70.86
Natural gas ($ per mcf)
2.91
3.19
2.48
The Alaska segment primarily explores for, produces, transports
and markets crude oil, NGLs and natural gas.
In 2020, Alaska contributed 28 percent of our consolidated
liquids production and less than 1 percent of our
consolidated natural gas production.
2020 vs. 2019
Net Income (Loss) Attributable to ConocoPhillips
Alaska reported a loss of $719 million in
2020, compared with earnings of $1,520 million
in 2019.
Earnings
were negatively impacted by:
●
Lower realized crude oil prices.
●
A $648 million after-tax impairment associated
with the carrying value of our Alaska North Slope
Gas
assets.
For additional information, see Note 7—Suspended
Wells and Exploration Expenses, in the
Notes to Consolidated Financial Statements.
●
Lower sales volumes, primarily due to normal field
decline and production curtailments
at our
operated assets on the North Slope—the Greater
Kuparuk Area (GKA) and Western North Slope
(WNS).
●
Higher DD&A expenses, primarily from
increased DD&A rates due to price-related downward
reserve revisions, partly offset by lower production
volumes.
●
Increased exploration expenses, primarily
due to higher dry hole costs and expenses related
to the
early cancellation of our winter exploration program.
Earnings were positively impacted by:
●
Lower production and operating expenses, primarily
associated with lower transportation and
terminaling costs as well as lower activities
across our assets.
Production
Average production decreased 20 MBOED in 2020 compared with 2019, primarily
due to:
●
Normal field decline.
●
Production curtailments at our operated assets on
the North Slope—GKA and WNS—of 8 MBOED
in response to the low crude oil price environment.
These production decreases were partly offset by:
●
Lower downtime due to the absence of planned
turnarounds at the Greater Prudhoe Area.
●
New wells online at our operated assets on the
North Slope—GKA and WNS.
Lower 48
2020
2019
2018
Net Income (Loss) Attributable to ConocoPhillips
(millions of dollars)
$
(1,122)
1,747
Average Net Production
Crude oil (MBD)
Natural gas liquids (MBD)
Natural gas (MMCFD)
Total Production
(MBOED)
Average Sales Prices
Crude oil ($ per bbl)
$
35.17
55.30
62.99
Natural gas liquids ($ per bbl)
12.13
16.83
27.30
Natural gas ($ per mcf)
1.65
2.12
2.82
The Lower 48 segment consists of operations located
in the contiguous U.S. and the Gulf of Mexico.
During
2020, the Lower 48 contributed 40 percent of our
consolidated liquids production and 44 percent of
our
consolidated natural gas production.
2020 vs. 2019
Net Income (Loss) Attributable to ConocoPhillips
Lower 48 reported a loss of $1,122 million in 2020,
compared with earnings of $436 million
in 2019.
Earnings were negatively impacted by:
●
Lower realized crude oil, NGL and natural gas prices.
●
Lower crude oil sales volumes due to normal
field decline and production curtailments.
●
Higher impairments, primarily related to developed
properties in our non-core assets which were
written down to fair value due to lower commodity
prices and development plan changes.
See Note
8—Impairments and Note 14—Fair Value Measurement, for additional information.
Earnings were positively impacted by:
●
Lower exploration expenses, primarily
due to the absence of a combined $197 million
after-tax of
leasehold impairment and dry hole costs associated
with our decision to discontinue exploration
activities in the Central Louisiana Austin
Chalk.
●
Lower DD&A expenses, primarily due to normal
field decline and production curtailments,
partly
offset by increased DD&A rates due to price-related downward
reserve revisions.
●
Lower production and operating expenses, primarily
due to lower activities driven by production
curtailments in response to the low price environment
and disposition impacts.
●
Lower taxes other than income taxes, primarily
due to lower realized prices and volumes.
Production
Total average production decreased 66 MBOED in 2020 compared with 2019,
primarily due to:
●
Normal field decline.
●
Production curtailments of approximately 55 MBOED
in response to the low crude oil price
environment.
These production decreases were partly offset by:
●
New wells online from the Eagle Ford, Permian and
Bakken.
Canada
2020*
2019**
2018**
Net Income (Loss) Attributable to ConocoPhillips
(millions of dollars)
$
(326)
Average Net Production
Crude oil (MBD)
Natural gas liquids (MBD)
-
Bitumen (MBD)
Natural gas (MMCFD)
Total Production
(MBOED)
Average Sales Prices
Crude oil ($ per bbl)
$
23.57
40.87
48.73
Natural gas liquids ($ per bbl)
5.41
19.87
43.70
Bitumen ($ per bbl)
8.02
31.72
22.29
Natural gas ($ per mcf)
1.21
0.49
1.00
*Average sales prices include unutilized transportation costs.
**Average prices for sales of bitumen produced excludes additional value realized from the purchase and sale of third-party volumes for
optimization of our
pipeline capacity between Canada and the U.S. Gulf
Coast.
Our Canadian operations consist of the Surmont
oil sands development in Alberta and the liquids-rich
Montney unconventional play in British Columbia.
In 2020, Canada contributed 9 percent of our
consolidated
liquids production and 3 percent of our consolidated
natural gas production.
2020 vs. 2019
Net Income (Loss) Attributable to ConocoPhillips
Canada operations reported a loss of $326 million
in 2020 compared with earnings of $279 million
in 2019.
Earnings decreased mainly due to:
●
Lower realized bitumen prices.
●
Higher DD&A expenses, primarily due to increased volumes and DD&A rates
from Montney production.
●
Lower bitumen sales due to production curtailments at Surmont.
Earnings were positively impacted by:
●
Increased Montney production from Pad 1 & 2 wells online and partial
year production from the Kelt
acquisition completed in August of 2020.
Production
Total average production increased 7 MBOED in 2020 compared with 2019.
The production increase was
primarily due to:
●
Increased liquids and natural gas production from Montney Pad 1 & 2 wells online
and partial year
production from the Kelt acquisition completed in August of 2020.
●
Decreased mandated production curtailments imposed by the Alberta government.
The production increase was partly offset by:
●
Lower bitumen production,
primarily due to voluntary curtailments at Surmont in response to the low price
environment of 12 MBOED.
Europe, Middle East and North Africa
2020
2019*
2018*
Net Income Attributable to ConocoPhillips
(millions of dollars)
$
3,170
2,594
Consolidated Operations
Average Net Production
Crude oil (MBD)
Natural gas liquids (MBD)
Natural gas (MMCFD)
Total Production
(MBOED)
Average Sales Prices
Crude oil ($ per bbl)
$
43.30
64.94
70.71
Natural gas liquids ($ per bbl)
23.27
29.37
36.87
Natural gas ($ per mcf)
3.23
4.92
7.65
*Prior periods have been updated to reflect the Middle East Business Unit
moving from Asia Pacific to the Europe, Middle East and North Africa
segment.
See Note 24—Segment Disclosures and Related Information in the Notes
to Consolidated Financial Statements for additional
information.
The Europe,
Middle East and North Africa segment consists
of operations principally located in the Norwegian
sector of the North Sea; the Norwegian Sea;
Qatar; Libya; and commercial and terminalling
operations in the
U.K.
In 2020, our Europe, Middle East and North
Africa operations contributed 13 percent of our consolidated
liquids production and 20 percent of our consolidated
natural gas production.
2020 vs. 2019
Net Income Attributable to ConocoPhillips
Earnings for Europe,
Middle East and North Africa operations
of $448 million decreased $2,722 million in
2020 compared with 2019.
The decrease in earnings was primarily
due to:
●
The absence of a $2.1 billion after-tax gain associated
with the completion of the sale of two
ConocoPhillips U.K. subsidiaries.
For additional information, see Note 4—Asset
Acquisitions and
Dispositions in the Notes to Consolidated Financial
Statements.
●
Lower equity in earnings of affiliates, primarily due to
lower LNG sales prices.
●
Lower realized crude oil prices in Norway.
In the fourth quarter of 2020, the effective tax rate within
our equity method investment in the Europe, Middle
East and North Africa segment increased.
Consolidated Production
Average consolidated production decreased 88 MBOED in 2020, compared with 2019.
The decrease was
mainly due to:
●
The absence of production related to our U.K.
disposition in the third quarter of 2019.
●
Lower volumes from Libya due to a cessation of
production following a period of civil unrest.
●
Normal field decline.
These production decreases were partly offset by:
●
New wells online in Norway.
Asia Pacific
2020
2019*
2018*
Net Income Attributable to ConocoPhillips
(millions of dollars)
$
1,483
1,342
Consolidated Operations
Average Net Production
Crude oil (MBD)
Natural gas liquids (MBD)
Natural gas (MMCFD)
Total Production
(MBOED)
Average Sales Prices
Crude oil ($ per bbl)
$
42.84
65.02
70.93
Natural gas liquids ($ per bbl)
33.21
37.85
47.20
Natural gas ($ per mcf)
5.39
5.91
6.15
*Prior periods have been updated to reflect the Middle East Business Unit
moving from Asia Pacific to the Europe, Middle East and North Africa
segment.
See Note 24—Segment Disclosures and Related Information in the Notes
to Consolidated Financial Statements for additional
information.
The Asia Pacific segment has operations in China,
Indonesia, Malaysia and Australia.
During 2020,
Asia Pacific
contributed 10 percent of our consolidated liquids
production and 32 percent of our consolidated
natural gas
production.
2020 vs. 2019
Net Income Attributable to ConocoPhillips
Asia Pacific reported earnings of $962 million
in 2020, compared with $1,483 million in
The decrease in
earnings was mainly due to:
●
Lower sales volumes, primarily from lower LNG
sales due to the Australia-West divestiture; lower
crude oil sales volumes in Malaysia, primarily
due to production curtailments; and lower crude
oil sales
volumes in China due to the expiration of the Panyu
production license.
For more information related to
our Australia-West divestiture, see Note 4—Asset Acquisitions and Dispositions in the
Notes to
Consolidated Financial Statements.
●
Lower realized commodity prices.
●
Lower equity in earnings of affiliates from APLNG, mainly
due to lower LNG sales prices.
●
The absence of a $164 million income tax benefit
related to deepwater incentive tax credits
from the
Malaysia Block G.
Earnings were positively impacted by:
●
A $597 million after-tax gain on disposition related
to our Australia-West divestiture.
Consolidated Production
Average consolidated production decreased 28 percent in 2020, compared with 2019.
The decrease was
primarily due to:
●
The divestiture of our Australia-West assets.
●
Normal field decline.
●
Higher unplanned downtime due to the rupture
of a third-party pipeline impacting gas production from
the Kebabangan Field in Malaysia.
●
The expiration of the Panyu production license in
China.
●
Production curtailments of 4 MBOED in Malaysia.
These production decreases were partly offset by:
●
Development activity at Bohai Bay in China and
Gumusut in Malaysia.
Other International
2020
2019
2018
Net Income (Loss) Attributable to ConocoPhillips
(millions of dollars)
$
(64)
The Other International segment includes exploration
activities in Colombia and Argentina and contingencies
associated with prior operations in other countries.
As a result of our completed Concho acquisition
on
January 15, 2021, we refocused our exploration
program and announced our intent to pursue a managed
exit
from certain areas.
2020 vs. 2019
Other International operations reported a loss of $64
million in 2020,
compared with earnings of $263 million
in 2019.
The decrease in earnings was primarily due
to:
●
The absence of $317 million after-tax in other
income from a settlement award with PDVSA
associated with prior operations in Venezuela.
For additional information related to this settlement
award, see Note 12—Contingencies and Commitments,
in the Notes to Consolidated Financial
Statements.
●
Increased exploration expenses, primarily
due to dry hole costs and a full impairment of
capitalized
undeveloped leasehold costs in Colombia.
Corporate and Other
Millions of Dollars
2020
2019
2018
Net Income (Loss) Attributable to ConocoPhillips
Net interest
$
(662)
(604)
(680)
Corporate general and administrative expenses
(200)
(252)
(91)
Technology
(26)
Other
(992)
(1,005)
$
(1,880)
(1,667)
2020 vs. 2019
Net interest consists of interest and financing expense,
net of interest income and capitalized interest.
Net
interest expense increased $58 million in 2020 compared
with 2019,
primarily due to lower interest income
related to lower cash and cash equivalent balances
and yield.
Corporate G&A expenses include compensation
programs and staff costs.
These costs decreased by $52
million in 2020 compared with 2019, primarily
due to mark to market adjustments associated
with certain
compensation programs.
Technology includes our investment in new technologies or businesses, as well as
licensing revenues.
Activities are focused on both conventional and tight
oil reservoirs, shale gas, heavy oil, oil
sands, enhanced
oil recovery and LNG.
Earnings from Technology decreased by $149 million in 2020 compared with 2019,
primarily due to lower licensing revenues.
The category “Other” includes certain foreign currency
transaction gains and losses, environmental costs
associated with sites no longer in operation, other
costs not directly associated with an operating
segment,
premiums incurred on the early retirement
of debt, unrealized holding gains or losses on equity
securities, and
pension settlement expense.
Earnings in “Other” decreased by $1,763 million
in 2020 compared with 2019,
primarily due to:
●
An unrealized loss of $855 million after-tax
on our CVE common shares in 2020,
compared with a
$649 million after-tax unrealized gain in 2019.
●
The absence of a $151 million tax benefit related
to the revaluation of deferred tax assets
following
finalization of rules related to the 2017 Tax Cuts and Jobs Act.
See Note 18—Income Taxes, in the
Notes to Consolidated Financial Statements,
for additional information related to the 2017 Tax Cuts
and Jobs Act.
CAPITAL RESOURCES AND LIQUIDITY
Financial Indicators
Millions of Dollars
Except as Indicated
2020
2019
2018
Net cash provided by operating activities
$
4,802
11,104
12,934
Cash and cash equivalents
2,991
5,088
5,915
Short-term investments
3,609
3,028
Short-term debt
Total debt
15,369
14,895
14,968
Total equity
29,849
35,050
32,064
Percent of total debt to capital*
%
Percent of floating-rate debt to total debt
%
*Capital includes total debt and total equity.
To meet our short-
and long-term liquidity requirements, we look
to a variety of funding sources, including
cash generated from operating activities,
proceeds from asset sales, our commercial paper
and credit facility
programs and our ability to sell securities
using our shelf registration statement.
In 2020, the primary uses of
our available cash were $4,715 million to support
our ongoing capital expenditures and investments
program;
$1,831 million to pay dividends on our common
stock; $892 million to repurchase our common
stock; and
$658 million for net purchase of investments.
During 2020, cash and cash equivalents decreased
by $2,097
million to $2,991 million.
We entered the year with a strong balance sheet including cash and cash equivalents
of over $5 billion, short-
term investments of $3 billion, and an undrawn
credit facility of $6 billion, totaling approximately
$14 billion
in available liquidity.
This strong foundation allowed us to be measured
in our response to the sudden change
in business environment as we exited the first
quarter of 2020.
In response to the oil market downturn
that
began in early 2020,
we announced the following capital, share repurchase
and operating cost reductions. We
reduced our 2020 operating plan capital expenditures
by a total of $2.3 billion, or approximately
thirty-five
percent of the original guidance.
We suspended our share repurchase program, further reducing cash outlays
by approximately $2 billion.
We also reduced our operating costs by approximately $0.6 billion,
or roughly
ten percent of the original 2020 guidance.
Collectively, these actions represent a reduction in 2020 cash uses of
approximately $5 billion versus the original operating
plan.
Considering the weakness in oil prices during the
second quarter of 2020, we established a framework
for
evaluating and implementing economic curtailments,
which resulted in taking an additional significant
step of
curtailing production, predominantly from
operated North American assets.
Due to our strong balance sheet,
we were in an advantaged position to forgo some production
and cash flow in anticipation of receiving higher
cash flows for those volumes in the future.
Based on our economic criteria, we began
restoring production
from voluntary curtailments in July, and with oil prices stabilizing around $40 per
barrel, we ended our
curtailment program by the end of the third quarter.
In the fourth quarter of 2020, we resumed
share repurchases, repurchasing $0.2 billion
of shares in October,
before suspending our share repurchase program
upon entry into a definitive agreement to
acquire Concho.
We resumed share repurchases in February 2021 after completion of our Concho
acquisition.
As of December 31, 2020,
we had cash and cash equivalents of $3.0 billion,
short-term investments of $3.6
billion, and available borrowing capacity under
our credit facility of $5.7 billion, totaling
over $12 billion of
liquidity.
We believe current cash balances and cash generated by operations, together with access to external
sources of funds as described below in the “Significant
Changes in Capital” section, will be sufficient
to meet
our funding requirements in the near- and long-term, including
our capital spending program, dividend
payments and required debt payments.
Significant Changes in Capital
Operating Activities
During 2020, cash provided by operating activities
was $4,802 million, a 57 percent decrease from 2019.
The
decrease was primarily due to lower realized
commodity prices, normal field decline,
production curtailments,
the divestiture of our U.K.
and Australia-West assets, and the absence in 2020 of collections under our
settlement agreement with PDVSA,
partially offset by lower production and operating
expenses.
Our short-
and long-term operating cash flows are highly
dependent upon prices for crude oil, bitumen, natural
gas, LNG and NGLs.
Prices and margins in our industry have historically
been volatile and are driven by
market conditions over which we have no control.
Absent other mitigating factors, as these
prices and margins
fluctuate, we would expect a corresponding
change in our operating cash flows.
The level of absolute production volumes, as
well as product and location mix, impacts our cash flows.
Full-
year production averaged 1,127 MBOED in 2020.
Full-year production excluding Libya averaged
1,118
MBOED in 2020.
Adjusting for estimated curtailments of approximately
80 MBOED;
closed acquisitions and
dispositions;
and excluding Libya; production for 2020 was 1,176 MBOED.
Production in 2021 is expected to
be approximately 1.5 MMBOED, reflecting the
impact from the Concho acquisition.
Future production is
subject to numerous uncertainties, including,
among others, the volatile crude oil and
natural gas price
environment, which may impact investment decisions;
the effects of price changes on production sharing
and
variable-royalty contracts; acquisition and disposition
of fields; field production decline rates; new
technologies; operating efficiencies; timing of startups
and major turnarounds; political instability;
weather-
related disruptions; and the addition of proved
reserves through exploratory success and
their timely and cost-
effective development.
While we actively manage these factors,
production levels can cause variability in cash
flows, although generally this variability
has not been as significant as that caused by commodity
prices.
To maintain or grow our production volumes on an ongoing basis, we must continue
to add to our proved
reserve base.
Our proved reserves generally increase as prices
rise and decrease as prices decline.
Reserve
replacement represents the net change in proved
reserves, net of production, divided by our current
year
production, as shown in our supplemental reserve table
disclosures.
Our reserve replacement was negative 86
percent in 2020, reflecting the impact of lower
prices, which reduced reserves by approximately
600 MMBOE.
Our organic reserve replacement, which excluded a net
decrease of 7 MMBOE from sales and purchases,
was
negative 84 percent in 2020.
In the three years ended December 31, 2020, our reserve
replacement was 59 percent, reflecting the impact
of
lower prices in 2020.
Our organic reserve replacement during the three years
ended December 31, 2020,
which excluded a net increase of 89 MMBOE related
to sales and purchases, was 53 percent.
For additional information about our 2021 capital
budget, see the “2021 Capital Budget” section
within
“Capital Resources and Liquidity” and for additional
information on proved reserves, including both
developed and undeveloped reserves, see the “Oil
and Gas Operations” section of this report.
As discussed in the “Critical Accounting Estimates”
section, engineering estimates of proved
reserves are
imprecise; therefore, each year reserves may be revised
upward or downward due to the impact of changes
in
commodity prices or as more technical data becomes
available on reservoirs.
It is not possible to reliably
predict how revisions will impact reserve quantities
in the future.
Investing Activities
In 2020, we invested $4.7 billion in capital
expenditures, of which $0.5 billion consisted of
strategic
acquisitions, including additional Montney acreage.
Capital expenditures invested in 2019 and 2018
were $6.6
billion and $6.8 billion,
respectively.
For information about our capital expenditures
and investments, see the
“Capital Expenditures and Investments”
section.
We invest in short-term investments as part of our cash investment strategy, the primary objective of which is
to protect principal, maintain liquidity and provide
yield and total returns;
these investments include time
deposits, commercial paper as well as debt securities
classified as available for sale.
Funds for short-term
needs to support our operating plan and provide resiliency
to react to short-term price volatility are invested
in
highly liquid instruments with maturities within
the year.
Funds we consider available to maintain resiliency
in longer term price downturns and to capture
opportunities outside a given operating
plan may be invested in
instruments with maturities greater than one year.
For additional information, see Note 1–Accounting
Policies
and Note 13–Derivative and Financial Instruments,
in the Notes to Consolidated Financial
Statements.
Investing activities in 2020 included net purchases
of $658 million of investments,
of which $420 million was
invested in short-term instruments and $238 million
was invested in long-term instruments.
Investing
activities in 2019 included net purchases of $2.9
billion of investments,
of which $2.8 billion was invested in
short-term instruments and $0.1 billion was invested
in long-term instruments.
For additional information, see
Note 13—Derivative and Financial Instruments,
in the Notes to Consolidated Financial
Statements.
Proceeds from asset sales in 2020 were $1.3 billion.
We received cash proceeds of $765 million for the
divestiture of our Australia-West assets and operations,
with another $200 million payment due upon final
investment decision of the proposed Barossa
development project.
We also received proceeds of $359 million
and $184 million for the sale of our Niobrara interests
and Waddell Ranch interests in the Lower 48,
respectively.
Proceeds from asset sales in 2019 were $3.0 billion,
including $2.2 billion for the sale of
two ConocoPhillips
U.K. subsidiaries and $350 million for
the sale of our 30 percent interest in the Greater
Sunrise Fields.
Proceeds from assets sales in 2018 were $1.1
billion, including several non-core assets in
the Lower 48, as
well as the sale of a ConocoPhillips subsidiary
which held 16.5 percent of our 24 percent interest
in the Clair
Field in the U.K.
For additional information on our dispositions,
see Note 4—Asset Acquisitions and
Dispositions in the Notes to Consolidated Financial
Statements.
Financing Activities
We have a revolving credit facility totaling $6.0 billion, expiring in May 2023.
Our revolving credit facility
may be used for direct bank borrowings, the issuance
of letters of credit totaling up to $500 million, or as
support for our commercial paper program.
The revolving credit facility is broadly syndicated
among financial
institutions and does not contain any material
adverse change provisions or any covenants
requiring
maintenance of specified financial ratios or credit
ratings.
The facility agreement contains a cross-default
provision relating to the failure to pay principal or
interest on other debt obligations of
$200 million or more
by ConocoPhillips, or any of its consolidated subsidiaries.
The amount of the facility is not subject to
the
redetermination prior to its expiration date.
Credit facility borrowings may bear interest at
a margin above rates offered by certain designated banks in the
London interbank market or at a margin above the overnight
federal funds rate or prime rates offered by
certain designated banks in the U.S.
The agreement calls for commitment fees
on available, but unused,
amounts.
The agreement also contains early termination
rights if our current directors or their approved
successors cease to be a majority of the Board
of Directors.
The revolving credit facility supports the ConocoPhillips
Company’s ability to issue up to $6.0 billion of
commercial paper, which is primarily a funding source for short-term
working capital needs.
Commercial
paper maturities are generally limited to 90 days.
With $300 million of commercial paper outstanding and no
direct borrowings or letters of credit,
we had $5.7 billion in available borrowing capacity
under the revolving
credit facility at December 31, 2020.
We may consider issuing additional commercial paper in the future to
supplement our cash position.
In October 2020, Moody’s affirmed its rating of our senior long-term debt of “A3”
with a “stable” outlook, and
affirmed its rating of our short-term debt as “Prime-2.”
In January 2021, Fitch affirmed its rating of our long-
term debt as “A” with a “stable” outlook and affirmed its
rating of our short-term debt as “F1+.”
On January
25, 2021, S&P revised the industry risk assessment
for the E&P industry to ‘Moderately High’ from
‘Intermediate’ based on a view of increasing
risks from the energy transition, price volatility, and weaker
profitability.
On February 11, 2021, S&P downgraded its rating of our long-term debt
from “A” to “A-” with a
“stable” outlook and downgraded its rating of our short-term
debt from “A-1” to “A-2.”
We do not have any
ratings triggers on any of our corporate debt
that would cause an automatic default, and
thereby impact our
access to liquidity, upon downgrade of our credit ratings.
If our credit ratings
are downgraded from their
current levels, it could increase the cost of corporate
debt available to us and restrict our access to
the
commercial paper markets.
If our credit rating were to deteriorate
to a level prohibiting us from accessing the
commercial paper market, we would still
be able to access funds under our revolving credit
facility.
Certain of our project-related contracts, commercial
contracts and derivative instruments contain
provisions
requiring us to post collateral.
Many of these contracts and instruments permit
us to post either cash or letters
of credit as collateral.
At December 31, 2020 and 2019, we had direct
bank letters of credit of $249 million
and $277 million, respectively, which secured performance obligations related to
various purchase
commitments incident to the ordinary conduct of
business.
In the event of credit
ratings downgrades, we may
be required to post additional letters of
credit.
On January 15, 2021, we completed the acquisition
of Concho in an all-stock transaction. In the acquisition,
we assumed Concho’s publicly traded debt.
On December 7, 2020, we launched an offer to exchange
Concho’s publicly traded debt for debt issued by ConocoPhillips.
The exchange offer settled on February 8,
Of the approximately $3.9 billion in aggregate
principal amount of Concho’s notes subject to the
exchange offer, 98 percent, or approximately $3.8 billion, was tendered and
exchanged for new debt issued by
ConocoPhillips.
There were no impacts to ConocoPhillips’
credit ratings as a result of the debt exchange.
For
additional information,
see Note 10—Debt and Note 25—Acquisition
of Concho Resources Inc., in the Notes
to Consolidated Financial Statements.
Shelf Registration
We have a universal shelf registration statement on file with the SEC under which
we have the ability to issue
and sell an indeterminate amount of various types
of debt and equity securities.
Guarantor Summarized Financial Information
We have various cross guarantees among ConocoPhillips, ConocoPhillips Company
and Burlington Resources
LLC, with respect to publicly held debt securities.
ConocoPhillips Company is 100 percent
owned by
ConocoPhillips.
Burlington Resources LLC is 100 percent
owned by ConocoPhillips Company.
ConocoPhillips and/or ConocoPhillips Company
have fully and unconditionally guaranteed
the payment
obligations of Burlington Resources LLC, with respect
to its publicly held debt securities.
Similarly,
ConocoPhillips has fully and unconditionally
guaranteed the payment obligations of ConocoPhillips
Company
with respect to its publicly held debt securities.
In addition, ConocoPhillips Company
has fully and
unconditionally guaranteed the payment obligations
of ConocoPhillips with respect to its publicly
held debt
securities.
All guarantees are joint and several.
In March of 2020, the SEC adopted amendments
to simplify the financial disclosure requirements
for
guarantors and issuers of guaranteed securities
registered under Rule 3-10 of Regulation S-X.
Based on our
evaluation of our existing guarantee relationships,
we qualify for the transition to alternative disclosures.
We
elected early voluntary compliance with the final
amendments beginning in the third quarter
of 2020.
Accordingly, condensed consolidating information by guarantor and issuer of
guaranteed securities will no
longer be reported, and alternative disclosures
of summarized financial information for the
consolidated
Obligor Group is presented.
The following tables present summarized financial
information for the Obligor
Group, as defined below:
●
The Obligor Group will reflect guarantors and issuers
of guaranteed securities consisting of
ConocoPhillips, ConocoPhillips Company and
Burlington Resources LLC.
●
Consolidating adjustments for elimination
of investments in and transactions between the collective
guarantors and issuers of guaranteed securities
are reflected in the balances of the summarized
financial information.
●
Non-Obligated Subsidiaries are excluded
from this presentation.
Transactions and balances reflecting activity between the Obligors
and Non-Obligated Subsidiaries are
presented separately below:
Summarized Income Statement Data
Millions of Dollars
2020
Revenues and Other Income
$
8,375
Income (loss) before income taxes
(2,999)
Net income (loss)
(2,701)
Net Income (Loss) Attributable to ConocoPhillips
(2,701)
Summarized Balance Sheet Data
Millions of Dollars
December 31, 2020
Current assets
$
8,535
Amounts due from Non-Obligated Subsidiaries, current
Noncurrent assets
37,180
Amounts due from Non-Obligated Subsidiaries, noncurrent
7,730
Current liabilities
3,797
Amounts due to Non-Obligated Subsidiaries, current
1,365
Noncurrent liabilities
18,627
Amounts due to Non-Obligated Subsidiaries, noncurrent
3,972
Capital Requirements
For information about our capital expenditures
and investments, see the “Capital Expenditures
and
Investments”
section.
Our debt balance at December 31, 2020, was $15,369
million, an increase of $474 million from
the balance at
December 31, 2019.
Maturities of debt (including payments for
finance leases) due in 2021 of $601 million,
excluding net unamortized premiums and discounts,
will be paid from current cash balances and cash
generated by operations.
For more information on Debt, see Note 10—Debt,
in the Notes to Consolidated
Financial Statements.
We believe in delivering value to our shareholders via a growing and sustainable dividend
supplemented by
additional returns of capital, including share repurchases.
In 2020, we paid $1,831 million, $1.69 per share of
common stock, in dividends. This is an increase
over 2019 and 2018, when we paid $1.34 and
$1.16 per share
of common stock, respectively.
In February 2021, we announced a quarterly dividend
of $0.43 per share,
payable March 1, 2021, to stockholders of record
at the close of business on February 12, 2021.
In late 2016, we initiated our current share repurchase
program, which has a current total program
authorization of $25 billion of our common stock.
Cost of share repurchases were $892 million,
$3,500
million and $2,999 million in 2020, 2019 and
2018,
respectively.
Share repurchases since inception of our
current program totaled 189
million shares at a cost of $10,517 million, as of
December 31, 2020.
In the
fourth quarter of 2020, we suspended share repurchases
upon entry into a definitive agreement
to acquire
Concho.
We resumed share repurchases in February 2021 after the completion of our Concho acquisition.
Repurchases are made at management’s discretion, at prevailing prices,
subject to market conditions and other
factors.
Our dividend and share repurchase programs are
subject to numerous considerations, including
market
conditions, management discretion and other factors.
See “Item 1A—Risk Factors
–
Our ability to declare and
pay dividends and repurchase shares is subject to
certain considerations.”
In addition to the requirements above, we have contractual
obligations for the purchase of goods and services
of approximately $8,123 million.
We expect to fulfill $2,805 million of these obligations in 2021. These
figures exclude purchase commitments
for jointly owned fields and facilities where
we are not the operator.
Purchase obligations of $5,237 million
are related to agreements to access and utilize
the capacity of third-
party equipment and facilities, including pipelines
and LNG product terminals, to transport, process,
treat and
store commodities.
Purchase obligations of $2,290 million are related
to market-based contracts for
commodity product purchases with third parties.
The remainder is primarily our net share
of purchase
commitments for materials and services for jointly
owned fields and facilities where we are the operator.
Capital Expenditures and Investments
Millions of Dollars
2020
2019
2018
Alaska
$
1,038
1,513
1,298
Lower 48
1,881
3,394
3,184
Canada
Europe, Middle East and North Africa
Asia Pacific
Other International
Corporate and Other
Capital Program
$
4,715
6,636
6,750
Our capital expenditures and investments
for the three-year period ended December 31,
2020 totaled $18.1
billion.
The 2020 expenditures supported key exploration
and developments, primarily:
●
Development and appraisal in the Lower 48, including
Eagle Ford, Permian, and Bakken.
●
Appraisal and development activities
in Alaska related to the Western North Slope; development
activities in the Greater Kuparuk Area and
the Greater Prudhoe Area.
●
Development and exploration activities
across assets in Norway.
●
Appraisal activities in liquids-rich plays and optimization
of oil sands development in Canada.
●
Continued development activities in China, Malaysia,
and Indonesia.
●
Exploration activities in Argentina.
2021 CAPITAL BUDGET
In February 2021, we announced 2021 operating
plan capital for the combined company of $5.5
billion.
The
plan includes $5.1 billion to sustain current
production and $0.4 billion for investment
in major projects,
primarily in Alaska, in addition to ongoing exploration
appraisal activity.
The operating plan capital budget of $5.5 billion
is expected to deliver production from the combined
company
of approximately 1.5 MMBOED in 2021.
This production guidance excludes Libya.
For information on PUDs and the associated costs
to develop these reserves, see the “Oil and Gas
Operations”
section in this report.
Contingencies
A number of lawsuits involving a variety of claims
arising in the ordinary course of business
have been filed
against ConocoPhillips.
We also may be required to remove or mitigate the effects on the environment of the
placement, storage, disposal or release of certain
chemical, mineral and petroleum substances
at various active
and inactive sites.
We regularly assess the need for accounting recognition or disclosure of these
contingencies.
In the case of all known contingencies (other
than those related to income taxes), we accrue
a
liability when the loss is probable and the amount
is reasonably estimable.
If a range of amounts can be
reasonably estimated and no amount within the range
is a better estimate than any other amount,
then the low
end of the range is accrued.
We do not reduce these liabilities for potential insurance or third-party recoveries.
We accrue receivables for insurance or other third-party recoveries when applicable.
With respect to income
tax-related contingencies, we use a cumulative probability-weighted
loss accrual in cases where sustaining a
tax position is less than certain.
Based on currently available information, we believe
it is remote that future costs related to known
contingent
liability exposures will exceed current accruals by
an amount that would have a material
adverse impact on our
consolidated financial statements.
For information on other contingencies, see
“Critical Accounting
Estimates” and Note 12—Contingencies and
Commitments, in the Notes to Consolidated
Financial Statements.
Legal and Tax Matters
We are subject to various lawsuits and claims including but not limited to matters
involving oil and gas royalty
and severance tax payments, gas measurement and
valuation methods, contract disputes,
environmental
damages, climate change, personal injury, and property damage.
Our primary exposures for such matters
relate to alleged royalty and tax underpayments
on certain federal, state and privately owned
properties and
claims of alleged environmental contamination
from historic operations.
We will continue to defend ourselves
vigorously in these matters.
Our legal organization applies its knowledge, experience
and professional judgment to the specific
characteristics of our cases, employing a litigation
management process to manage and monitor the
legal
proceedings against us.
Our process facilitates the early evaluation and
quantification of potential exposures in
individual cases.
This process also enables us to track those cases that
have been scheduled for trial and/or
mediation.
Based on professional judgment and experience
in using these litigation management tools and
available information about current developments
in all our cases, our legal organization regularly assesses
the
adequacy of current accruals and determines if
adjustment of existing accruals, or establishment
of new
accruals, is required.
See Note 18—Income Taxes, in the Notes to Consolidated Financial Statements,
for
additional information about income tax-related
contingencies.
Environmental
We are subject to the same numerous international, federal, state and local environmental
laws and regulations
as other companies in our industry.
The most significant of these environmental
laws and regulations include,
among others, the:
●
U.S. Federal Clean Air Act, which governs
air emissions.
●
U.S. Federal Clean Water Act, which governs discharges to water bodies.
●
European Union Regulation for Registration, Evaluation,
Authorization and Restriction of Chemicals
(REACH).
●
U.S. Federal Comprehensive Environmental
Response, Compensation and Liability Act
(CERCLA or
Superfund), which imposes liability on generators,
transporters and arrangers of hazardous substances
at sites where hazardous substance releases have
occurred or are threatening to occur.
●
U.S. Federal Resource Conservation and Recovery
Act (RCRA), which governs the treatment,
storage
and disposal of solid waste.
●
U.S. Federal Oil Pollution Act of 1990 (OPA90), under which owners and operators
of onshore
facilities and pipelines, lessees or permittees
of an area in which an offshore facility is located, and
owners and operators of vessels are liable for
removal costs and damages that result from
a discharge
of oil into navigable waters of the U.S.
●
U.S. Federal Emergency Planning and Community Right-to-Know
Act (EPCRA), which requires
facilities to report toxic chemical inventories
with local emergency planning committees and response
departments.
●
U.S. Federal Safe Drinking Water Act, which governs the disposal of wastewater
in underground
injection wells.
●
U.S. Department of the Interior regulations,
which relate to offshore oil and gas operations in U.S.
waters and impose liability for the cost of pollution
cleanup resulting from operations, as well as
potential liability for pollution damages.
●
European Union Trading Directive resulting in European
Emissions Trading Scheme.
These laws and their implementing regulations
set limits on emissions and, in the case of discharges to
water,
establish water quality limits and establish standards
and impose obligations for the remediation
of releases of
hazardous substances and hazardous wastes.
They also, in most cases, require permits in
association with new
or modified operations.
These permits can require an applicant to
collect substantial information in connection
with the application process, which can be expensive
and time consuming.
In addition, there can be delays
associated with notice and comment periods and
the agency’s processing of the application.
Many of the
delays associated with the permitting process
are beyond the control of the applicant.
Many states and foreign countries where
we operate also have, or are developing, similar
environmental laws
and regulations governing these same types of
activities.
While similar, in some cases these regulations may
impose additional, or more stringent, requirements
that can add to the cost and difficulty of marketing
or
transporting products across state and international
borders.
The ultimate financial impact arising from
environmental laws and regulations is neither
clearly known nor
easily determinable as new standards, such as
air emission standards and water quality standards,
continue to
evolve.
However, environmental laws and regulations, including those that
may arise to address concerns
about global climate change, are expected to continue
to have an increasing impact on our operations
in the
U.S. and in other countries in which we operate.
Notable areas of potential impacts include air emission
compliance and remediation obligations in
the U.S. and Canada.
An example is the use of hydraulic fracturing,
an essential completion technique that facilitates
production of
oil and natural gas otherwise trapped in lower
permeability rock formations.
A range of local, state, federal or
national laws and regulations currently govern
hydraulic fracturing operations, with hydraulic
fracturing
currently prohibited in some jurisdictions.
Although hydraulic fracturing has been conducted
for many
decades, a number of new laws, regulations
and permitting requirements are under consideration
by various
state environmental agencies, and others which
could result in increased costs, operating restrictions,
operational delays and/or limit the ability
to develop oil and natural gas resources.
Governmental restrictions
on hydraulic fracturing could impact the overall
profitability or viability of certain of our oil
and natural gas
investments.
We have adopted operating principles that incorporate established industry standards
designed to
meet or exceed government requirements.
Our practices continually evolve as technology
improves and
regulations change.
We also are subject to certain laws and regulations relating to environmental remediation
obligations
associated with current and past operations.
Such laws and regulations include CERCLA
and RCRA and their
state equivalents.
Longer-term expenditures are subject to considerable
uncertainty and may fluctuate
significantly.
We occasionally receive requests for information or notices of potential liability
from the EPA and state
environmental agencies alleging we are a potentially
responsible party under CERCLA or an equivalent
state
statute.
On occasion, we also have been made a party
to cost recovery litigation by those agencies
or by
private parties.
These requests, notices and lawsuits assert
potential liability for remediation costs at various
sites that typically are not owned by us, but allegedly
contain wastes attributable to our past operations.
As of
December 31, 2020, there were 15 sites around
the U.S. in which we were identified as
a potentially
responsible party under CERCLA and comparable
state laws.
For most Superfund sites, our potential liability
will be significantly less than the total site
remediation costs
because the percentage of waste attributable
to us, versus that attributable to all other
potentially responsible
parties, is relatively low.
Although liability of those potentially
responsible is generally joint and several for
federal sites and frequently so for state sites,
other potentially responsible parties at sites
where we are a party
typically have had the financial strength to
meet their obligations, and where they have
not, or where
potentially responsible parties could not be located,
our share of liability has not increased materially.
Many of
the sites at which we are potentially responsible
are still under investigation by the EPA or the state agencies
concerned.
Prior to actual cleanup, those potentially responsible
normally assess site conditions, apportion
responsibility and determine the appropriate remediation.
In some instances, we may have no liability
or attain
a settlement of liability.
Actual cleanup costs generally occur after the parties
obtain EPA or equivalent state
agency approval.
There are relatively few sites where we
are a major participant, and given the timing
and
amounts of anticipated expenditures, neither the
cost of remediation at those sites nor
such costs at all
CERCLA sites, in the aggregate, is expected to
have a material adverse effect on our competitive
or financial
condition.
Expensed environmental costs were $393 million
in 2020 and are expected to be about $435 million
per year
in 2021 and 2022.
Capitalized environmental costs were $161 million
in 2020 and are expected to be about
$210 million per year in 2021 and 2022.
Accrued liabilities for remediation activities
are not reduced for potential recoveries from insurers
or other
third parties and are not discounted (except those
assumed in a purchase business combination,
which we do
record on a discounted basis).
Many of these liabilities result from CERCLA,
RCRA and similar state or international laws that
require us to
undertake certain investigative and remedial
activities at sites where we conduct, or once
conducted,
operations or at sites where ConocoPhillips-generated
waste was disposed.
The accrual also includes a number
of sites we identified that may require environmental
remediation, but which are not currently the
subject of
CERCLA, RCRA or other agency enforcement
activities.
The laws that require or address environmental
remediation may apply retroactively and regardless
of fault, the legality of the original activities
or the current
ownership or control of sites.
If applicable, we accrue receivables for probable
insurance or other third-party
recoveries.
In the future, we may incur significant costs
under both CERCLA and RCRA.
Remediation activities vary substantially
in duration and cost from site to site, depending on the
mix of unique
site characteristics, evolving remediation technologies,
diverse regulatory agencies and enforcement
policies,
and the presence or absence of potentially liable
third parties.
Therefore, it is difficult to develop reasonable
estimates of future site remediation costs.
At December 31, 2020, our balance sheet included
total accrued environmental costs of
$180 million,
compared with $171 million at December 31,
2019, for remediation activities in the
U.S. and Canada.
We
expect to incur a substantial amount of these expenditures
within the next 30 years.
Notwithstanding any of the foregoing, and as
with other companies engaged in similar businesses,
environmental costs and liabilities are inherent
concerns in our operations and products, and there
can be no
assurance that material costs and liabilities
will not be incurred.
However, we currently do not expect any
material adverse effect upon our results of operations or financial
position as a result of compliance with
current environmental laws and regulations.
Climate Change
Continuing political and social attention to the
issue of global climate change has resulted in a broad
range of
proposed or promulgated state, national and international
laws focusing on GHG reduction.
These proposed or
promulgated laws apply or could apply in countries
where we have interests or may have interests
in the future.
Laws in this field continue to evolve, and
while it is not possible to accurately estimate either
a timetable for
implementation or our future compliance costs
relating to implementation, such laws, if
enacted, could have a
material impact on our results of operations and
financial condition.
Examples of legislation and precursors
for possible regulation that do or could affect our operations
include:
●
European Emissions Trading Scheme (ETS), the program through
which many of the EU member
states are implementing the Kyoto Protocol.
Our cost of compliance with the EU ETS in
2020 was
approximately $7 million before-tax.
●
The Alberta Technology Innovation and Emissions Reduction (TIER) regulation
requires any existing
facility with emissions equal to or greater than 100,000
metric tonnes of carbon dioxide, or equivalent,
per year to meet a facility benchmark intensity.
The total cost of these regulations in 2020
was
approximately $2 million.
●
The U.S. Supreme Court decision in Massachusetts
v. EPA
,
549 U.S. 497, 127 S.Ct. 1438 (2007),
confirmed that the EPA has the authority to regulate carbon dioxide as an “air pollutant”
under the
Federal Clean Air Act.
●
The U.S. EPA’s
announcement on March 29, 2010 (published
as “Interpretation of Regulations that
Determine Pollutants Covered by Clean Air Act
Permitting Programs,” 75 Fed. Reg. 17004 (April
2,
2010)), and the EPA’s
and U.S. Department of Transportation’s joint promulgation of a Final Rule on
April 1, 2010, that triggers regulation of GHGs
under the Clean Air Act, may trigger more
climate-
based claims for damages, and may result in longer
agency review time for development projects.
●
The U.S. EPA’s
announcement on January 14, 2015, outlining
a series of steps it plans to take to
address methane and smog-forming volatile organic compound
emissions from the oil and gas
industry.
The U.S. government established a goal of
reducing the 2012 levels in methane emissions
from the oil and gas industry by 40 to 45 percent
by 2025.
●
Carbon taxes in certain jurisdictions.
Our cost of compliance with Norwegian carbon
tax legislation
in 2020 was approximately $29 million (net
share before-tax).
We also incur a carbon tax for
emissions from fossil fuel combustion in our
British Columbia and Alberta operations in
Canada,
totaling approximately $3.5 million (net share
before-tax).
●
The agreement reached in Paris in December 2015
at the 21
st
Conference of the Parties to the United
Nations Framework Convention on Climate
Change, setting out a process for achieving
global
emission reductions.
The new administration has recommitted
the United States to the Paris
Agreement, and a significant number of U.S. state
and local governments and major corporations
headquartered in the U.S. have also announced
related commitments.
In the U.S., some additional form of regulation
may be forthcoming in the future at the
federal and state levels
with respect to GHG emissions.
Such regulation could take any of several
forms that may result in the creation
of additional costs in the form of taxes, the restriction
of output, investments of capital to maintain
compliance
with laws and regulations, or required acquisition
or trading of emission allowances.
We are working to
continuously improve operational and energy efficiency through
resource and energy conservation throughout
our operations.
Compliance with changes in laws and regulations
that create a GHG tax, emission trading scheme
or GHG
reduction policies could significantly increase
our costs, reduce demand for fossil energy derived
products,
impact the cost and availability of capital
and increase our exposure to litigation.
Such laws and regulations
could also increase demand for less carbon intensive
energy sources, including natural gas.
The ultimate
impact on our financial performance, either positive
or negative, will depend on a number of factors,
including
but not limited to:
●
Whether and to what extent legislation or
regulation is enacted.
●
The timing of the introduction of such legislation
or regulation.
●
The nature of the legislation (such as a cap and
trade system or a tax on emissions) or
regulation.
●
The price placed on GHG emissions (either
by the market or through a tax).
●
The GHG reductions required.
●
The price and availability of offsets.
●
The amount and allocation of allowances.
●
Technological and scientific developments leading to new products or services.
●
Any potential significant physical effects of climate
change (such as increased severe weather events,
changes in sea levels and changes in temperature).
●
Whether, and the extent to which, increased compliance costs are
ultimately reflected in the prices of
our products and services.
Climate Change Litigation
Beginning in 2017, governmental and other entities
in several states in the U.S. have filed lawsuits
against oil
and gas companies, including ConocoPhillips,
seeking compensatory damages and equitable
relief to abate
alleged climate change impacts.
Additional lawsuits with similar allegations
are expected to be filed.
The
amounts claimed by plaintiffs are unspecified and the legal
and factual issues involved in these cases are
unprecedented.
ConocoPhillips believes these lawsuits are
factually and legally meritless and are an
inappropriate vehicle to address the challenges
associated with climate change and will
vigorously defend
against such lawsuits.
Several Louisiana parishes and the State of Louisiana
have filed 43 lawsuits under Louisiana’s State and Local
Coastal Resources Management Act (SLCRMA)
against oil and gas companies, including ConocoPhillips,
seeking compensatory damages for contamination
and erosion of the Louisiana coastline
allegedly caused by
historical oil and gas operations.
ConocoPhillips entities are defendants
in 22 of the lawsuits and will
vigorously defend against them.
Because Plaintiffs’ SLCRMA theories are unprecedented,
there is uncertainty
about these claims (both as to scope and damages)
and any potential financial impact on the company.
Company Response to Climate-Related Risks
The company has responded by putting in place
a Sustainable Development Risk Management Standard
covering the assessment and registering of significant
and high sustainable development risks based
on their
consequence and likelihood of occurrence.
We have developed a company-wide Climate Change Action Plan
with the goal of tracking mitigation activities
for each climate-related risk included in the corporate
Sustainable Development Risk Register.
The risks addressed in our Climate Change Action
Plan fall into four broad categories:
●
GHG-related legislation and regulation.
●
GHG emissions management.
●
Physical climate-related impacts.
●
Climate-related disclosure and reporting.
Emissions are categorized into three different scopes.
Gross operated Scope 1 and Scope 2 GHG emissions
help us understand our climate transition
risk.
●
Scope 1 emissions are direct GHG emissions
from sources that we own or control.
●
Scope 2 emissions are GHG emissions from
the generation of purchased electricity or
steam that we
consume.
Scope 3 emissions are indirect emissions
from sources that we neither own nor control.
We announced in October 2020 the adoption of a Paris-aligned climate risk framework
with the objective of
implementing a coherent set of choices designed
to facilitate the success of our existing exploration
and
production business through the energy transition.
Given the uncertainties remaining about how the
energy
transition will evolve, the strategy aims to be robust
across a range of potential future outcomes.
The strategy is comprised of four pillars:
●
Targets:
Our target framework consists of a hierarchy of targets, from a long-term
ambition that sets
the direction and aim of the strategy, to a medium-term performance target for GHG emissions
intensity, to shorter-term targets for flaring and methane intensity reductions. These
performance
targets are supported by lower-level internal business
unit goals to enable the company to achieve the
company-wide targets.
We have set a target to reduce our gross operated (scope 1 and 2) emissions
intensity by 35 to 45 percent from 2016 levels by
2030, with an ambition to achieve net-zero
operated
emissions by 2050.
We have joined the World
Bank Flaring Initiative to work towards
zero routine
flaring of gas by 2030.
●
Technology choices:
We expanded our Marginal Abatement Cost Curve process to provide a broader
range of opportunities for emission reduction
technology.
●
Portfolio choices:
Our corporate authorization process requires
all qualifying projects to include a
GHG price in their project approval economics.
Different GHG prices are used depending on the
region or jurisdiction.
Projects in jurisdictions with existing GHG
pricing regimes incorporate the
existing GHG price and forecast into their
economics.
Projects where no existing GHG pricing
regime exists utilize a scenario forecast from our
internally consistent World Energy Model.
In this
way, both existing and emerging regulatory requirements are considered in our decision-making.
The
company does not use an estimated market cost
of GHG emissions when assessing reserves
in
jurisdictions without existing GHG regulations.
●
External engagement: Our external engagement
aims to differentiate ConocoPhillips within the oil and
gas sector with our approach to managing climate-related
risk.
We are a Founding Member of the
Climate Leadership Council (CLC), an international
policy institute founded in collaboration
with
business and environmental interests to develop
a carbon dividend plan.
Participation in the CLC
provides another opportunity for ongoing dialogue
about carbon pricing and framing the issues
in
alignment with our public policy principles.
We also belong to and fund Americans For Carbon
Dividends, the education and advocacy branch of
the CLC.
CRITICAL ACCOUNTING ESTIMATES
The preparation of financial statements
in conformity with GAAP requires management
to select appropriate
accounting policies and to make estimates and
assumptions that affect the reported amounts of assets,
liabilities, revenues and expenses.
See Note 1—Accounting Policies, in the Notes
to Consolidated Financial
Statements, for descriptions of our major accounting
policies.
Certain of these accounting policies involve
judgments and uncertainties to such an extent there
is a reasonable likelihood materially different amounts
would have been reported under different conditions, or if
different assumptions had been used.
These critical
accounting estimates are discussed with the Audit
and Finance Committee of the Board of Directors at
least
annually.
We believe the following discussions of critical accounting estimates, along
with the discussion of
deferred tax asset valuation allowances in this
report, address all important accounting
areas where the nature
of accounting estimates or assumptions is material
due to the levels of subjectivity and judgment necessary
to
account for highly uncertain matters or the
susceptibility of such matters to change.
Oil and Gas Accounting
Accounting for oil and gas exploratory activity
is subject to special accounting rules unique
to the oil and gas
industry.
The acquisition of G&G seismic information,
prior to the discovery of proved reserves, is
expensed
as incurred, similar to accounting for research and
development costs.
However, leasehold acquisition costs
and exploratory well costs are capitalized on the
balance sheet pending determination of whether
proved oil
and gas reserves have been recognized.
Property Acquisition Costs
For individually significant leaseholds, management
periodically assesses for impairment based on
exploration
and drilling efforts to date.
For relatively small individual leasehold acquisition
costs, management exercises
judgment and determines a percentage probability
that the prospect ultimately will fail to find
proved oil and
gas reserves and pools that leasehold information
with others in the geographic area.
For prospects in areas
with limited, or no, previous exploratory drilling,
the percentage probability of ultimate failure
is normally
judged to be quite high.
This judgmental percentage is multiplied
by the leasehold acquisition cost, and that
product is divided by the contractual period
of the leasehold to determine a periodic leasehold
impairment
charge that is reported in exploration expense.
This judgmental probability percentage is reassessed
and
adjusted throughout the contractual period of the
leasehold based on favorable or unfavorable
exploratory
activity on the leasehold or on adjacent leaseholds,
and leasehold impairment amortization expense is
adjusted
prospectively.
At year-end 2020, the remaining $2.4 billion of net capitalized
unproved property costs consisted primarily
of
individually significant leaseholds, mineral rights
held in perpetuity by title ownership, exploratory
wells
currently being drilled, suspended exploratory
wells, and capitalized interest.
Of this amount, approximately
$1.9 billion is concentrated in 10 major development
areas, the majority of which are not expected to
move to
proved properties in 2021.
Management periodically assesses individually
significant leaseholds for
impairment based on the results of exploration
and drilling efforts and the outlook for commercialization.
Exploratory Costs
For exploratory wells, drilling costs are temporarily
capitalized, or “suspended,” on the balance sheet,
pending
a determination of whether potentially economic
oil and gas reserves have been discovered by the
drilling
effort to justify development.
If exploratory wells encounter potentially economic
quantities of oil and gas, the well costs
remain capitalized
on the balance sheet as long as sufficient progress assessing
the reserves and the economic and operating
viability of the project is being made.
The accounting notion of “sufficient progress” is
a judgmental area, but
the accounting rules do prohibit continued capitalization
of suspended well costs on the expectation
future
market conditions will improve or new technologies
will be found that would make the development
economically profitable.
Often, the ability to move into the development
phase and record proved reserves is
dependent on obtaining permits and government
or co-venturer approvals, the timing of which is
ultimately
beyond our control.
Exploratory well costs remain suspended as long
as we are actively pursuing such
approvals and permits, and believe they will be obtained.
Once all required approvals and permits have
been
obtained, the projects are moved into the development
phase, and the oil and gas reserves are designated
as
proved reserves.
For complex exploratory discoveries, it
is not unusual to have exploratory wells remain
suspended on the balance sheet for several
years while we perform additional appraisal
drilling and seismic
work on the potential oil and gas field or while
we seek government or co-venturer approval of development
plans or seek environmental permitting.
Once a determination is made the well did not
encounter potentially
economic oil and gas quantities, the well costs
are expensed as a dry hole and reported in
exploration expense.
Management reviews suspended well balances quarterly, continuously monitors
the results of the additional
appraisal drilling and seismic work, and expenses
the suspended well costs as a dry hole when it
determines
the potential field does not warrant further
investment in the near term.
Criteria utilized in making this
determination include evaluation of the reservoir
characteristics and hydrocarbon properties,
expected
development costs, ability to apply existing technology
to produce the reserves, fiscal terms,
regulations or
contract negotiations, and our expected return
on investment.
At year-end 2020,
total suspended well costs were $682 million,
compared with $1,020 million at year-end
For additional information on suspended wells,
including an aging analysis, see Note 7—Suspended
Wells and Exploration Expenses, in the Notes to Consolidated Financial Statements.
Proved Reserves
Engineering estimates of the quantities of proved reserves
are inherently imprecise and represent only
approximate amounts because of the judgments involved
in developing such information.
Reserve estimates
are based on geological and engineering assessments
of in-place hydrocarbon volumes, the production
plan,
historical extraction recovery and processing yield
factors, installed plant operating capacity
and approved
operating limits.
The reliability of these estimates at any point
in time depends on both the quality and
quantity of the technical and economic data
and the efficiency of extracting and processing the
hydrocarbons.
Despite the inherent imprecision in these engineering
estimates, accounting rules require disclosure
of
“proved” reserve estimates due to the importance
of these estimates to better understand the perceived
value
and future cash flows of a company’s operations.
There are several authoritative guidelines
regarding the
engineering criteria that must be met before estimated
reserves can be designated as “proved.”
Our
geosciences and reservoir engineering organization
has policies and procedures in place consistent
with these
authoritative guidelines.
We have trained and experienced internal engineering personnel who estimate
our
proved reserves held by consolidated companies, as
well as our share of equity affiliates.
Proved reserve estimates are adjusted annually
in the fourth quarter and during the year
if significant changes
occur, and take into account recent production and subsurface
information about each field.
Also, as required
by current authoritative guidelines, the estimated
future date when an asset will reach the end
of its economic
life is based on 12-month average prices and current
costs.
This date estimates when production will end and
affects the amount of estimated reserves.
Therefore, as prices and cost levels change from
year to year, the
estimate of proved reserves also changes.
Generally, our proved reserves decrease as prices decline and
increase as prices rise.
Our proved reserves include estimated quantities
related to PSCs, reported under the “economic interest”
method, as well as variable-royalty regimes,
and are subject to fluctuations in commodity
prices; recoverable
operating expenses; and capital costs.
If costs remain stable, reserve quantities
attributable to recovery of costs
will change inversely to changes in commodity
prices.
We would expect reserves from these contracts to
decrease when product prices rise and increase
when prices decline.
The estimation of proved developed reserves also
is important to the income statement because
the proved
developed reserve estimate for a field serves as the
denominator in the unit-of-production
calculation of the
DD&A of the capitalized costs for that asset.
At year-end 2020, the net book value of productive PP&E
subject to a unit-of-production calculation was
approximately $33 billion and the DD&A recorded
on these
assets in 2020 was approximately $5.3 billion.
The estimated proved developed reserves for
our consolidated
operations were 3.2 billion BOE at the end
of 2019 and 2.5 billion BOE at the end of
If the estimates of
proved reserves used in the unit-of-production
calculations had been lower by 10 percent
across all
calculations, before-tax DD&A in 2020
would have increased by an estimated $588
million.
Impairments
Long-lived assets used in operations are assessed
for impairment whenever changes in facts
and circumstances
indicate a possible significant deterioration
in future cash flows expected to be generated
by an asset group.
If
there is an indication the carrying amount of
an asset may not be recovered, a recoverability
test is performed
using management’s assumptions for prices, volumes and future development
plans.
If, upon review, the sum
of the undiscounted cash flows before income-taxes
is less than the carrying value of the asset
group, the
carrying value is written down to estimated fair
value and reported as impairments in the
periods in which the
determination is made.
Individual assets are grouped for impairment
purposes at the lowest level for which
there are identifiable cash flows that are largely independent
of the cash flows of other groups of assets—
generally on a field-by-field basis for E&P assets.
Because there usually is a lack of quoted
market prices for
long-lived assets, the fair value of impaired assets
is typically determined based on the present
values of
expected future cash flows using discount rates
and prices believed to be consistent with
those used by
principal market participants,
or based on a multiple of operating cash flow validated
with historical market
transactions of similar assets where possible.
The expected future cash flows used for
impairment reviews and
related fair value calculations are based on estimated
future production volumes, commodity
prices, operating
costs and capital decisions, considering all
available information at the date of review.
Differing assumptions
could affect the timing and the amount of an impairment
in any period.
See Note 8—Impairments, in the
Notes to Consolidated Financial Statements,
for additional information.
Investments in nonconsolidated entities
accounted for under the equity method are assessed
for impairment
whenever changes in the facts and circumstances indicate
a loss in value has occurred.
Such evidence of a loss
in value might include our inability to
recover the carrying amount, the lack of sustained
earnings capacity
which would justify the current investment amount,
or a current fair value less than the investment’s carrying
amount.
When such a condition is judgmentally determined
to be other than temporary, an impairment charge
is recognized for the difference between the investment’s carrying value and its estimated
fair value.
When
determining whether a decline in value is other than
temporary, management considers factors such as the
length of time and extent of the decline, the investee’s financial condition
and near-term prospects, and our
ability and intention to retain our investment for
a period that will be sufficient to allow for any anticipated
recovery in the market value of the investment.
Since quoted market prices are usually not
available, the fair
value is typically based on the present value
of expected future cash flows using discount
rates and prices
believed to be consistent with those used by principal
market participants, plus market analysis
of comparable
assets owned by the investee, if appropriate.
Differing assumptions could affect the timing and the amount of
an impairment of an investment in any period.
See the “APLNG” section of Note 5—Investments,
Loans and
Long-Term Receivables,
in the Notes to Consolidated Financial
Statements, for additional information.
Asset Retirement Obligations and Environmental Costs
Under various contracts, permits and regulations,
we have material legal obligations to remove
tangible
equipment and restore the land or seabed at the
end of operations at operational sites.
Our largest asset
removal obligations involve plugging and abandonment
of wells, removal and disposal of offshore oil and
gas
platforms around the world, as well as oil and gas
production facilities and pipelines in Alaska.
The fair values
of obligations for dismantling and removing these
facilities are recorded as a liability and
an increase to PP&E
at the time of installation of the asset based on estimated
discounted costs.
Fair value is estimated using a
present value approach, incorporating assumptions
about estimated amounts and timing of settlements
and
impacts of the use of technologies.
Estimating future asset removal costs requires
significant judgement.
Most
of these removal obligations are many years, or decades,
in the future and the contracts and regulations
often
have vague descriptions of what removal practices
and criteria must be met when the removal
event actually
occurs.
The carrying value of our asset retirement
obligation estimate is sensitive to inputs such as asset
removal technologies and costs, regulatory and other
compliance considerations, expenditure timing,
and other
inputs into valuation of the obligation, including
discount and inflation rates, which are all
subject to change
between the time of initial recognition of the liability
and future settlement of our obligation.
Normally, changes in asset removal obligations are reflected in the income statement
as increases or decreases
to DD&A over the remaining life of the assets.
However, for assets at or nearing the end of their operations, as
well as previously sold assets for which we
retained the asset removal obligation, an increase
in the asset
removal obligation can result in an immediate
charge to earnings, because any increase in PP&E
due to the
increased obligation would immediately be subject
to impairment, due to the low fair value of these
properties.
In addition to asset removal obligations, under the
above or similar contracts, permits and regulations,
we have
certain environmental-related projects.
These are primarily related to remediation
activities required by
Canada and various states
within the U.S. at exploration and production sites.
Future environmental
remediation costs are difficult to estimate because they are
subject to change due to such factors as the
uncertain magnitude of cleanup costs, the unknown
time and extent of such remedial actions
that may be
required, and the determination of our liability
in proportion to that of other responsible parties.
See Note 9—
Asset Retirement Obligations and Accrued Environmental
Costs, in the Notes to Consolidated Financial
Statements, for additional information.
Projected Benefit Obligations
Determination of the projected benefit obligations
for our defined benefit pension and postretirement
plans are
important to the recorded amounts for such obligations
on the balance sheet and to the amount of benefit
expense in the income statement.
The actuarial determination of projected benefit
obligations and company
contribution requirements involves judgment about
uncertain future events, including estimated
retirement
dates, salary levels at retirement, mortality
rates, lump-sum election rates, rates of return on plan
assets, future
health care cost-trend rates, and rates of utilization
of health care services by retirees.
Due to the specialized
nature of these calculations, we engage outside actuarial
firms to assist in the determination of these
projected
benefit obligations and company contribution requirements.
For Employee Retirement Income Security Act-
governed pension plans, the actuary exercises fiduciary
care on behalf of plan participants in the
determination
of the judgmental assumptions used in determining
required company contributions into the
plans.
Due to
differing objectives and requirements between financial
accounting rules and the pension plan funding
regulations promulgated by governmental agencies,
the actuarial methods and assumptions
for the two
purposes differ in certain important respects.
Ultimately, we will be required to fund all vested benefits under
pension and postretirement benefit plans not
funded by plan assets or investment returns,
but the judgmental
assumptions used in the actuarial calculations
significantly affect periodic financial statements and funding
patterns over time.
Projected benefit obligations are particularly
sensitive to the discount rate assumption.
A
100 basis-point decrease in the discount rate assumption
would increase projected benefit obligations
by
$1,200 million.
Benefit expense is sensitive to the discount rate
and return on plan assets assumptions.
A
100 basis-point decrease in the discount rate assumption
would increase annual benefit expense by
$110 million, while a 100 basis-point decrease in the return
on plan assets assumption would increase annual
benefit expense by $80 million.
In determining the discount rate, we use yields
on high-quality fixed income
investments matched to the estimated benefit
cash flows of our plans.
We are also exposed to the possibility
that lump sum retirement benefits taken from pension
plans during the year could exceed the total of
service
and interest components of annual pension expense
and trigger accelerated recognition of a portion
of
unrecognized net actuarial losses and gains.
These benefit payments are based on decisions
by plan
participants and are therefore difficult to predict.
In the event there is a significant reduction in the
expected
years of future service of present employees or the
elimination of the accrual of defined benefits
for some or all
of their future services for a significant number
of employees, we could recognize a curtailment
gain or loss.
See Note 17—Employee Benefit Plans, in the
Notes to Consolidated Financial Statements,
for additional
information.
Contingencies
A number of claims and lawsuits are made against
the company arising in the ordinary course of
business.
Management exercises judgment related to accounting
and disclosure of these claims which includes
losses,
damages, and underpayments associated with environmental
remediation, tax, contracts, and other legal
disputes.
As we learn new facts concerning contingencies,
we reassess our position both with respect to
amounts recognized and disclosed considering changes
to the probability of additional losses and potential
exposure.
However, actual losses can and do vary from estimates
for a variety of reasons including legal,
arbitration, or other third-party decisions; settlement
discussions; evaluation of scope of damages;
interpretation of regulatory or contractual terms;
expected timing of future actions; and proportion
of liability
shared with other responsible parties.
Estimated future costs related to contingencies
are subject to change as
events evolve and as additional information becomes
available during the administrative and litigation
processes.
For additional information on contingent
liabilities, see the “Contingencies” section
within “Capital
Resources and Liquidity” and Note 12—Contingencies
and Commitments, in the Notes to Consolidated
Financial Statements.
Income Taxes
We are subject to income taxation in numerous jurisdictions worldwide.
We record deferred tax assets and
liabilities to account for the expected future tax
consequences of events that have been recognized
in our
financial statements and our tax returns.
We routinely assess our deferred tax assets and reduce such assets by
a valuation allowance if we deem it is more
likely than not that some portion, or all,
of the deferred tax assets
will not be realized.
In assessing the need for adjustments
to existing valuation allowances, we consider all
available positive and negative evidence. Positive
evidence includes reversals of temporary
differences,
forecasts of future taxable income, assessment of
future business assumptions and applicable
tax planning
strategies that are prudent and feasible. Negative
evidence includes losses in recent years
as well as the
forecasts of future net income (loss) in the realizable
period. In making our assessment regarding
valuation
allowances, we weight the evidence based on
objectivity.
Numerous judgments and assumptions are inherent
in the determination of future taxable income, including
factors such as future operating conditions
and the
assessment of the effects of foreign taxes on our U.S. federal
income taxes (particularly as related to prevailing
oil and gas prices).
See Note 18—Income Taxes for additional information, in the Notes to Consolidated
Financial Statements.
We regularly assess and, if required, establish accruals for uncertain tax positions that
could result from
assessments of additional tax by taxing jurisdictions
in countries where we operate.
We recognize a tax benefit
from an uncertain tax position when it is more
likely than not that the position will be sustained
upon
examination, based on the technical merits
of the position.
These accruals for uncertain tax positions are
subject to a significant amount of judgment and
are reviewed and adjusted on a periodic basis
in light of
changing facts and circumstances considering the
progress of ongoing tax audits, court proceedings,
changes in
applicable tax laws, including tax case rulings and
legislative guidance, or expiration of the
applicable statute
of limitations.
See Note 18—Income Taxes for additional information, in the Notes to Consolidated
Financial
Statements.
CAUTIONARY STATEMENT
FOR THE PURPOSES OF THE “SAFE HARBOR”
PROVISIONS OF
THE PRIVATE
SECURITIES LITIGATION REFORM ACT OF 1995
This report includes forward-looking statements
within the meaning of Section 27A of the Securities
Act of
1933 and Section 21E of the Securities Exchange
Act of 1934.
All statements other than statements of
historical fact included or incorporated by reference in
this report, including, without limitation,
statements
regarding our future financial position, business
strategy, budgets, projected revenues, projected costs and
plans, objectives of management for future operations,
the anticipated benefits of the transaction
between us
and Concho, the anticipated impact of the transaction
on the combined company’s business and future
financial and operating results, the expected amount
and the timing of synergies from the transaction
are
forward-looking statements.
Examples of forward-looking statements contained
in this report include our
expected production growth and outlook on the
business environment generally, our expected capital budget
and capital expenditures, and discussions concerning
future dividends.
You can often identify our forward-
looking statements by the words “anticipate,” “believe,”
“budget,” “continue,” “could,” “effort,” “estimate,”
“expect,” “forecast,” “intend,” “goal,” “guidance,”
“may,” “objective,” “outlook,” “plan,” “potential,”
“predict,” “projection,” “seek,” “should,” “target,” “will,”
“would” and similar expressions.
We based the forward-looking statements on our current expectations, estimates
and projections about
ourselves and the industries in which we operate in
general.
We caution you these statements are not
guarantees of future performance as they involve
assumptions that, while made in good faith,
may prove to be
incorrect, and involve risks and uncertainties
we cannot predict.
In addition, we based many of these forward-
looking statements on assumptions about future events
that may prove to be inaccurate.
Accordingly, our
actual outcomes and results may differ materially from
what we have expressed or forecast in the forward-
looking statements.
Any differences could result from a variety of factors
and uncertainties, including, but not
limited to, the following:
●
The impact of public health crises, including pandemics
(such as COVID-19) and epidemics and any
related company or government policies or
actions.
●
Global and regional changes in the demand, supply, prices, differentials or other market
conditions
affecting oil and gas, including changes resulting from a
public health crisis or from the imposition or
lifting of crude oil production quotas or other
actions that might be imposed by OPEC
and other
producing countries and the resulting company
or third-party actions in response to such changes.
●
Fluctuations in crude oil, bitumen, natural gas,
LNG and NGLs prices, including a prolonged
decline
in these prices relative to historical or future
expected levels.
●
The impact of significant declines in prices for
crude oil, bitumen, natural gas, LNG and NGLs,
which
may result in recognition of impairment charges on
our long-lived assets, leaseholds and
nonconsolidated equity investments.
●
Potential failures or delays in achieving expected
reserve or production levels from existing
and future
oil and gas developments, including due to operating
hazards, drilling risks and the inherent
uncertainties in predicting reserves and reservoir
performance.
●
Reductions in reserves replacement rates, whether
as a result of the significant declines in commodity
prices or otherwise.
●
Unsuccessful exploratory drilling activities
or the inability to obtain access to exploratory
acreage.
●
Unexpected changes in costs or technical requirements
for constructing, modifying or operating E&P
facilities.
●
Legislative and regulatory initiatives
addressing environmental concerns, including initiatives
addressing the impact of global climate change or further
regulating hydraulic fracturing, methane
emissions, flaring or water disposal.
●
Lack of, or disruptions in, adequate and reliable
transportation for our crude oil, bitumen, natural
gas,
LNG and NGLs.
●
Inability to timely obtain or maintain permits,
including those necessary for construction, drilling
and/or development, or inability to make capital
expenditures required to maintain compliance
with
any necessary permits or applicable laws or regulations.
●
Failure to complete definitive agreements and feasibility
studies for, and to complete construction of,
announced and future E&P and LNG development
in a timely manner (if at all) or on
budget.
●
Potential disruption or interruption of our operations
due to accidents, extraordinary weather
events,
civil unrest, political events, war, terrorism, cyber attacks,
and information technology failures,
constraints or disruptions.
●
Changes in international monetary conditions and
foreign currency exchange rate fluctuations.
●
Changes in international trade relationships,
including the imposition of trade restrictions
or tariffs
relating to crude oil, bitumen, natural gas,
LNG, NGLs and any materials or products (such
as
aluminum and steel) used in the operation of our
business.
●
Substantial investment in and development use
of, competing or alternative energy sources, including
as a result of existing or future environmental
rules and regulations.
●
Liability for remedial actions, including removal
and reclamation obligations, under existing
and
future environmental regulations and litigation.
●
Significant operational or investment changes imposed
by existing or future environmental
statutes
and regulations, including international agreements
and national or regional legislation and regulatory
measures to limit or reduce GHG emissions.
●
Liability resulting from litigation, including the
potential for litigation related to the
transaction with
Concho, or our failure to comply with applicable
laws and regulations.
●
General domestic and international economic and
political developments, including armed
hostilities;
expropriation of assets; changes in governmental
policies relating to crude oil, bitumen, natural
gas,
LNG and NGLs pricing;
regulation or taxation; and other political, economic
or diplomatic
developments.
●
Volatility
in the commodity futures markets.
●
Changes in tax and other laws, regulations (including
alternative energy mandates), or royalty rules
applicable to our business.
●
Competition and consolidation in the oil and gas E&P
industry.
●
Any limitations on our access to capital or increase
in our cost of capital, including as a result
of
illiquidity or uncertainty in domestic or international
financial markets or investment sentiment.
●
Our inability to execute, or delays in the completion,
of any asset dispositions or acquisitions
we elect
to pursue.
●
Potential failure to obtain, or delays in obtaining,
any necessary regulatory approvals for
pending or
future asset dispositions or acquisitions,
or that such approvals may require modification
to the terms
of the transactions or the operation of our remaining
business.
●
Potential disruption of our operations as a result
of pending or future asset dispositions or acquisitions,
including the diversion of management time and
attention.
●
Our inability to deploy the net proceeds from any
asset dispositions that are pending or
that we elect to
undertake in the future in the manner and timeframe
we currently anticipate, if at all.
●
Our inability to liquidate the common stock issued
to us by Cenovus Energy as part of our sale of
certain assets in western Canada at prices we deem
acceptable, or at all.
●
The operation and financing of our joint ventures.
●
The ability of our customers and other contractual
counterparties to satisfy their obligations to us,
including our ability to collect payments
when due from the government of Venezuela or PDVSA.
●
Our inability to realize anticipated cost savings
and capital expenditure reductions.
●
The inadequacy of storage capacity for our products,
and ensuing curtailments, whether voluntary
or
involuntary, required to mitigate this physical constraint.
●
Our ability to successfully integrate Concho’s business.
●
The risk that the expected benefits and cost
reductions associated with the transaction with
Concho
may not be fully achieved in a timely manner, or at all.
●
The risk that we will be unable to retain and hire
key personnel.
●
Unanticipated difficulties or expenditures relating to
integration with Concho.
●
Uncertainty as to the long-term value of our common
stock.
●
The diversion of management time on integration-related
matters.
●
The factors generally described in Item 1A—Risk
Factors in this 2020 Annual Report on Form 10-K
and any additional risks described in our other filings
with the SEC.
Previous: Item 5. MARKET FOR REGISTRANT’S COMMON · Next: Item 7A. QUANTITATIVE